# ProPetro Holding Corp. (PUMP) Informational only - not investment advice. CIK: 0001680247 SIC: 1389 Oil & Gas Field Services, NEC SIC breadcrumb: [Mining](/division/B/) > [SIC Major Group 13](/major-group/13/) > [SIC 1389 Oil & Gas Field Services, NEC](/industry/1389/) Latest 10-K filed: 2026-02-19 SEC page: https://www.sec.gov/edgar/browse/?CIK=1680247 Filing source: https://www.sec.gov/Archives/edgar/data/1680247/000168024726000028/pump-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 1269158000 | USD | 2025 | 2026-02-19 | | Net income | 824000 | USD | 2025 | 2026-02-19 | | Assets | 1290890000 | USD | 2025 | 2026-02-19 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-19. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001680247.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts. | Metric | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | | 981,865,000 | 1,704,562,000 | 2,052,314,000 | 789,232,000 | 874,514,000 | 1,279,701,000 | 1,630,399,000 | 1,444,286,000 | 1,269,158,000 | | Net income | -53,147,000 | 12,613,000 | 173,862,000 | 163,010,000 | -107,020,000 | -54,185,000 | 2,030,000 | 85,634,000 | -137,859,000 | 824,000 | | Operating income | -67,386,000 | 24,113,000 | 232,669,000 | 221,362,000 | -131,243,000 | -68,696,000 | -2,591,000 | 130,343,000 | -166,960,000 | 6,350,000 | | Diluted EPS | -1.19 | 0.16 | 2.00 | 1.57 | -1.06 | -0.53 | 0.02 | 0.76 | -1.31 | 0.01 | | Operating cash flow | 10,659,000 | 109,257,000 | 393,079,000 | 455,290,000 | 139,124,000 | 154,714,000 | 300,429,000 | 374,742,000 | 252,295,000 | 231,607,000 | | Capital expenditures | 42,832,000 | 285,891,000 | 284,197,000 | 502,894,000 | 100,603,000 | 143,523,000 | 319,683,000 | 370,869,000 | 140,297,000 | 186,316,000 | | Share buybacks | | | | | | 0.00 | 0.00 | 51,738,000 | 59,108,000 | 0.00 | | Assets | 541,422,000 | 719,032,000 | 1,274,522,000 | 1,436,111,000 | 1,050,739,000 | 1,061,236,000 | 1,335,786,000 | 1,480,312,000 | 1,223,645,000 | 1,290,890,000 | | Liabilities | 320,413,000 | 305,780,000 | 477,167,000 | 466,806,000 | 179,968,000 | 234,934,000 | 381,753,000 | 481,920,000 | 407,372,000 | 461,048,000 | | Stockholders' equity | 221,009,000 | 413,252,000 | 797,355,000 | 969,305,000 | 870,771,000 | 826,302,000 | 954,033,000 | 998,392,000 | 816,273,000 | 829,842,000 | | Cash and cash equivalents | 133,596,000 | 23,949,000 | 132,700,000 | 149,036,000 | 68,772,000 | 111,918,000 | 78,862,000 | 33,354,000 | 50,443,000 | 91,334,000 | | Free cash flow | -32,173,000 | -176,634,000 | 108,882,000 | -47,604,000 | 38,521,000 | 11,191,000 | -19,254,000 | 3,873,000 | 111,998,000 | 45,291,000 | ### Ratios ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported. | Metric | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Net margin | | 1.28% | 10.20% | 7.94% | -13.56% | -6.20% | 0.16% | 5.25% | -9.55% | 0.06% | | Operating margin | | 2.46% | 13.65% | 10.79% | -16.63% | -7.86% | -0.20% | 7.99% | -11.56% | 0.50% | | Return on equity | -24.05% | 3.05% | 21.80% | 16.82% | -12.29% | -6.56% | 0.21% | 8.58% | -16.89% | 0.10% | | Return on assets | -9.82% | 1.75% | 13.64% | 11.35% | -10.19% | -5.11% | 0.15% | 5.78% | -11.27% | 0.06% | | Liabilities / equity | 1.45 | 0.74 | 0.60 | 0.48 | 0.21 | 0.28 | 0.40 | 0.48 | 0.50 | 0.56 | | Current ratio | 1.66 | 0.97 | 0.99 | 1.61 | 1.61 | 1.44 | 1.16 | 1.15 | 1.31 | 1.29 | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-30. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001680247.json. Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived. | Quarter | End date | Revenue | Net income | Diluted EPS | Method | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q2 | 2022-06-30 | | | -0.32 | reported discrete quarter | | 2022-Q3 | 2022-09-30 | | | 0.10 | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | | 0.25 | reported discrete quarter | | 2023-Q2 | 2023-03-31 | | 28,733,000 | | reported discrete quarter | | 2023-Q2 | 2023-06-30 | 435,249,000 | | 0.34 | reported discrete quarter | | 2023-Q3 | 2023-06-30 | | 39,257,000 | | reported discrete quarter | | 2023-Q3 | 2023-09-30 | 423,804,000 | | 0.31 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 347,776,000 | -17,109,000 | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 405,843,000 | 19,930,000 | 0.18 | reported discrete quarter | | 2024-Q2 | 2024-03-31 | | 19,930,000 | | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 357,021,000 | | -0.03 | reported discrete quarter | | 2024-Q3 | 2024-06-30 | | -3,660,000 | | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 360,868,000 | | -1.32 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 320,554,000 | -17,062,000 | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 359,416,000 | 9,602,000 | 0.09 | reported discrete quarter | | 2025-Q2 | 2025-03-31 | | 9,602,000 | | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 326,151,000 | | -0.07 | reported discrete quarter | | 2025-Q3 | 2025-06-30 | | -7,155,000 | | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 293,916,000 | | -0.02 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 289,675,000 | 742,000 | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 270,685,000 | -3,643,000 | -0.03 | reported discrete quarter | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance - [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States - [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States - [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States - [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States - [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States - [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized - [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized - [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks - [GDP](/indicator/GDP/): Gross Domestic Product - [GPDI](/indicator/GPDI/): Gross Private Domestic Investment - [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment - [PCEC](/indicator/PCEC/): Personal Consumption Expenditures - [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services - [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt - [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product - [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit - [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts - [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures - [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing - [USCONS](/indicator/USCONS/): All Employees, Construction - [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade - [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities - [USGOVT](/indicator/USGOVT/): All Employees, Government - [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private - [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods - [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft - [BUSINV](/indicator/BUSINV/): Total Business Inventories - [EXPGS](/indicator/EXPGS/): Exports of Goods and Services - [IMPGS](/indicator/IMPGS/): Imports of Goods and Services - [IR](/indicator/IR/): Import Price Index (End Use): All Commodities - [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/1680247/000168024726000060/pump-20260331.htm Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high Filing date: 2026-04-30 Report date: 2026-03-31 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 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. Through our subsidiary, ProPetro Energy Solutions, LLC, ("PROPWR"), we provide turnkey power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers using mobile power generation equipment installed at customers’ sites. Our completion services include our operating segments comprised of hydraulic fracturing, wireline and cementing operations. Our hydraulic fracturing operations account for approximately 66.1% of our total revenues and operations as of March 31, 2026. Our total available hydraulic horsepower ("HHP") as of March 31, 2026, was 1,254,500 HHP, which was comprised of 447,500 HHP of our Tier IV DGB dual-fuel equipment, 312,000 HHP of FORCE® electric-powered equipment and 495,000 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 completions equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region’s increasingly high-intensity well completions (including simultaneous hydraulic fracturing ("Simul-Frac"), which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In 2021, we began to transition our fleet from traditional equipment to Tier IV DGB dual-fuel equipment. In 2022, we entered into three-year electric fleet leases which commenced in 2023 and 2024 for four FORCE® electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet and in 2024, we entered into an additional three-year lease for a fifth FORCE® electric-powered hydraulic fracturing fleet with 72,000 HHP (collectively the "Electric Fleet Leases"). The equipment under these leases represent all of our FORCE® electric-powered equipment. We currently have 28 wireline units and 29 cementing units. In December 2024, we formed PROPWR to provide power generation services and represent our Power Generation operating segment. This subsidiary began revenue-generating activities during the third quarter of fiscal year 2025 and has entered into contractual arrangements with equipment manufacturers to purchase mobile natural gas-fueled power generation equipment, including turbine generator sets, reciprocating engines, auxiliary equipment and battery energy storage solution equipment. We have received certain units of this equipment and anticipate all remaining ordered units will be delivered by year-end 2027. As of March 31, 2026, we had total committed capacity of approximately 240 megawatts and total delivered or on-order generation capacity of approximately 550 megawatts, split approximately 70% and 30% between high-efficiency reciprocating engine generators and low emissions modular turbines, respectively. We continue to actively negotiate additional contracts amid increasing demand for power solutions and to explore various financing alternatives for our power equipment. We primarily provide hydraulic fracturing, wireline and cementing completion services to E&P companies in the Permian Basin and power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. We compete against different companies in each service and product line we offer. The markets in which we operate are highly competitive. To be successful, an energy services company must provide services and equipment 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 quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in E&P companies' 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 energy service industry because of the capital requirements, lack of large scale deployment of certain new technology such as electric-powered equipment, and the pricing of 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, -28- equipment quality and technology, 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. 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. 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, Cementing and Power Generation operating segments meet the criteria of a reportable segment. Prior to the third quarter of fiscal year 2025, our Power Generation segment did not meet the quantitative thresholds for a reportable segment. Accordingly, it was shown in the "All Other" category. Effective as of the third quarter of fiscal year 2025, Power Generation is shown as a reportable segment since it meets the criteria of a reportable segment. Additionally, our corporate administrative activities do not involve business activities from which they may earn revenues. As a result, corporate administrative expenses and intersegment revenue have been included under "Reconciling Items." Corporate administrative expenses are included in the reconciliation of net (loss) income to Adjusted EBITDA below. Prior period segment information has been revised to conform to our current presentation. For additional financial information on our reportable segments presentation, see "Note 6 - 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, LLC (the "Pioneer Pressure Pumping Acquisition") in exchange for 16.6 million shares of our common stock and $110.0 million in cash. In May 2024, Pioneer merged with and into a wholly owned subsidiary of Exxon Mobil Corporation ("ExxonMobil") after which ExxonMobil became the owner of these shares. The Company currently provides pressure pumping, wireline and other services to ExxonMobil and previously provided such services to Pioneer. On April 22, 2024, we entered into a sub-agreement for Hydraulic Fracturing Services with XTO Energy Inc., a wholly owned subsidiary of ExxonMobil ("XTO"), pursuant to which we will provide hydraulic fracturing, wireline and pumpdown services with two committed FORCE® electric-powered hydraulic fracturing fleets and the option to add a third FORCE® fleet (also with wireline and pumpdown services) for a certain number of contracted hours with respect to each fleet, subject to certain termination and release rights. We expect this agreement will expire in late 2026. At this time, we do not expect such agreement to be renewed or extended and, if we are not able to procure additional work from XTO, we will be required to redeploy the equipment associated with the affected fleets with other customers. 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 the war between Israel, Iran and the United States has contributed to significant volatility in crude oil prices, with the spot price per barrel of the West Texas Intermediate ("WTI") average crude oil price increasing to approximately $91 per barrel in March 2026 compared to approximately $58 per barrel in December 2025 as a result of disruptions to crude oil production the Middle East and global shipping constraints. In addition, the war between Russia and Ukraine, including the associated sanctions, events in Venezuela and actions by OPEC+ have contributed to volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing in recent years. Additionally, we have recently experienced a decrease in the Permian Basin rig count to 247 at the end of 2025 and a further decrease to 242 at the end of March 2026, according to the Baker Hughes Company, which resulted in less predictable demand for completion services and pressure on pricing of [Excerpt truncated for page length; source filing is linked above.] ## Latest 10-K MD&A Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high 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, 2023, and the comparison of our results of operations for the years ended December 31, 2024, and 2023, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 20, 2025. 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 73.2% of our total revenues and operations. Our total available hydraulic horsepower (“HHP”) at December 31, 2025, was 1,259,500 HHP, which was comprised of 445,000 HHP of our Tier IV Dynamic Gas Blending (“DGB”) dual-fuel equipment, 312,000 HHP of FORCE® electric-powered equipment and 502,500 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 2021, we began to transition our fleet from traditional equipment to Tier IV DGB dual-fuel equipment. In 2022, we entered into three-year electric fleet leases which commenced in 2023 and 2024 for four FORCE® electric-powered hydraulic fracturing fleets worth of equipment with 60,000 HHP per fleet and in 2024, we entered into an additional three-year lease for one more FORCE® electric-powered hydraulic fracturing fleet worth of equipment with 72,000 HHP (collectively the “Electric Fleet Leases”). As of December 31, 2025, we have received 312,000 HHP of FORCE® electric-powered equipment representing five fleets worth of equipment. In December 2024, we formed a new subsidiary, ProPetro Energy Solutions, LLC, (“PROPWR”), which provides turnkey power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers using mobile power generation equipment installed at customers’ sites. This subsidiary began revenue-generating activities during the third quarter of fiscal year 2025 and has entered into contractual arrangements with equipment manufacturers to purchase mobile natural gas-fueled power generation equipment, including turbine generator sets, reciprocating engines, auxiliary equipment and battery energy storage solution equipment. As of February 19, 2026 we had total committed capacity of approximately 240 megawatts and total delivered or on-order generation capacity of approximately 550 megawatts, split approximately 70% and 30% between high-efficiency reciprocating engine generators and low emissions modular turbines, respectively. We anticipate all ordered units will be delivered by year-end 2027. We continue to actively 37 negotiate additional contracts amid increasing demand for power solutions and to explore various financing alternatives for our power equipment. On November 1, 2024, we sold our cementing business located in Vernal, Utah, to a business owned by a former employee as part of a strategic repositioning. We received a promissory note for $13.0 million as consideration, and recorded a gain on disposal of $8.2 million related to the sale of the business. The note receivable was secured by substantially all assets of the divested operations and the former employee’s ownership interests in and distributions from the business. The note receivable was to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025, to December 31, 2029, but was fully repaid with interest in December 2025. 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. 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. As of December 31, 2025, we conducted our business through four operating segments: Hydraulic Fracturing, Wireline, Cementing and Power Generation, all of which meet the criteria of a reportable segment. Prior to the third quarter of fiscal year 2025, our Power Generation segment did not meet the quantitative thresholds for a reportable segment and prior to the fourth quarter of fiscal year 2024, our Cementing segment did not meet the quantitative thresholds for a reportable segment. Accordingly, they were shown in the “All Other” category. Effective as of the third quarter of fiscal year 2025 and the fourth quarter of fiscal year 2024, Power Generation and Cementing, respectively, are shown as reportable segments since they meet the criteria of a reportable segment. 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. 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 and the option to add a third FORCE® fleet (also with wireline and pumpdown services) for a certain number of contracted hours with respect to each fleet, subject to certain termination and release rights. This agreement will expire in approximately late 2026. At this time, we do not expect such agreement to be renewed or extended and, if we are not able to procure additional work from XTO, we will be required to redeploy the equipment associated with the affected fleets with other customers. 38 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 taken by the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “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 WTI average crude oil price declined to approximately $65 per barrel in 2025 compared to approximately $76 per barrel in 2024 in response to tariff policies implemented by the United States 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 Permian Basin rig count to 304 at the end of 2024 and a further decrease to 247 at the end of 2025, according to the Baker Hughes Company (“Baker Hughes”), 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 changes in the United States’ trade policy, including the imposition of tariffs and the resulting consequences, would negatively impact our business, financial condition and results of operations. 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 into 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. To the extent any of our customers have certain expectations or requirements with respect to emissions reductions from their contractors, if we are unable to continue quickly transitioning to lower emissions equipment, the demand for our services could be adversely impacted. If the Permian Basin rig count and market conditions improve, including improved pricing for our services and labor availability, and we are able to meet our customers' lower emissions equipment demands, we believe our operational and financial results will also improve. If the rig count or market conditions do not improve or decline in the future, and we are unable to increase our pricing or pass-through future cost increases to our customers, there could be a material adverse impact on our business, results of operations and cash flows. Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to the holiday season, inclement winter weather and the exhaustion of our customers' annual budgets. As a result, we typically experience declines in our operating and financial results in November and December, even in a stable commodity price and operations environment. 39 2025 Operational Highlights Over the course of the year ended December 31, 2025: •we maintained operational and financial stability during a challenging operating environment faced by the broader energy markets and the completions market in the Permian Basin through our disciplined approach to cost and fleet management and focusing on consistent performance; •our active hydraulic fracturing fleet count declined from 15 active fleets at the beginning of the year to 11 at the end of the year as we idled certain fleets to preserve them for more favorable market conditions, rather than run them at sub-economic levels; and •we secured contracts with multiple customers for our PROPWRSM power generation business and deployed our first mobile power generation equipment in the field during the third quarter of fiscal year 2025 and ended the year with total delivered or on-order generation capacity of approximately 550 megawatts, split approximately 70% and 30% between high-efficiency reciprocating engine generators and low emissions modular turbines, respectively. We anticipate all ordered units will be delivered by year-end 2027. As of February 19, 2026, we had total committed capacity of approximately 240 megawatts. 2025 Financial Highlights Financial highlights for the year ended December 31, 2025: •net income was $0.8 million, compared to net loss of $137.9 million for the year ended December 31, 2024. Diluted net income per common share was $0.01, compared to diluted net loss of $1.31 for the year ended December 31, 2024. Net loss for the year ended December 31, 2024 included property and equipment impairment expense of $188.6 million related to our conventional Tier II diesel-only hydraulic fracturing pumping units and associated conventional assets (“Tier II Units”) and goodwill impairment expense of $23.6 million related to the goodwill in our Wireline operating segment. Adjusted EBITDA of approximately $208.4 million decreased 26.4%, compared to $283.2 million for the year ended December 31, 2024 (see reconciliation of Adjusted EBITDA to net income in the subsequent section “How We Evaluate Our Operations”); •capital expenditures incurred increased to $281.2 million, an increase of 111% as compared to 2024. Capital expenditures incurred included $198.4 million related to equipment orders for our Power Generation operating segment; •secured a financing arrangement with Caterpillar Financial Services Corporation (“Caterpillar”) for a maximum total available amount of $103.7 million to support the purchase of certain natural gas-fueled power generation equipment; •secured a lease facility described in “Note 17. Leases” with Stonebriar Commercial Finance LLC for the right, but not the obligation, to fund up to $350.0 million of purchases of power generator equipment; •net cash provided by operating activities less net cash used in investing activities declined by $15.4 million compared to 2024; and •our total liquidity was $205.4 million as of December 31, 2025. consisting of cash and cash equivalents of $91.3 million and remaining availability of $114.1 million under our ABL Credit Facility; we had total outstanding debt of $122.6 million as of December 31, 2025, comprising of $45.0 million of borrowings under our ABL Credit Facility and $77.6 million of equipment financing interim and term loans under the Caterpillar Equipment Loan Agreement (as defined below). Recent Developments In January 2026, the Company sold 17.3 million shares of its common stock in an underwritten public offering for $10.00 per share, pursuant to an effective shelf registration statement on Form S-3 filed with the SEC, including shares sold pursuant to the option granted to the underwriters to purchase up to an additional 2.3 million shares of our common stock (the “2026 Common Stock Offering”). The Company received approximately $163.3 million in net proceeds from this sale after deducting underwriting discounts and commissions and estimated offering expenses. The Company intends to use the net proceeds from this sale for general corporate purposes, including to fund growth capital for additional power generation equipment. 40 In February 2026, the Company entered into an amendment to the Caterpillar Equipment Loan Agreement, under which Caterpillar increased the availability of funds by $53.6 million, which resulted in a maximum total available amount of $157.3 million to support the purchase of certain natural gas-fueled power generation equipment. Our Assets and Operations Completion services include our hydraulic fracturing, wireline and cementing operations. We primarily provide these services to E&P companies in the Permian Basin. We also provide turnkey power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. During the year ended December 31, 2025, our hydraulic fracturing, wireline, cementing and power generation operations accounted for approximately 73.2%, 16.5%, 10.3%, and 0% of our total revenue, respectively. Our completion services equipment has been designed to handle Permian Basin specific operating conditions and the region’s increasingly high‑intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. Our power generation operations consist of mobile natural gas-fueled power generation equipment, including turbine generator sets, reciprocating engines, auxiliary equipment and battery energy storage solution equipment. We plan to continually reinvest in our equipment to ensure optimal performance and reliability. How We Generate Revenue We generate revenue predominantly through our completion services, and more specifically, by providing hydraulic fracturing services to our customers. We operate a fleet of mobile hydraulic fracturing, wireline and cementing units and other auxiliary equipment to perform completion services to E&P companies. Additionally, we generate revenue through our PROPWRSM power generation business by providing turnkey power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers using mobile power generation equipment installed at customers’ sites. These services are generally provided through contractual arrangements in which we set a price per unit of power generated or a price per period and a minimum quantity of power per period under our contracts. We also provide personnel and services that are tailored to meet each of our customers’ needs. 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 completion services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil price per barrel was approximately $65, $76, and $78 for the years ended December 31, 2025, 2024, and 2023, respectively. In January 2026, the WTI oil price was approximately $60 per barrel. If the WTI oil price declines in the future or remains highly volatile, demand for our services may be negatively impacted, which could result in a significant decrease in our future profitability and cash flows. We monitor oil and natural gas prices and the Permian Basin rig count to enable us to more effectively plan our business and forecast the demand for our services. 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) 2025 2024 2023 Directional 10  3  3  Horizontal 257  296  323  Vertical 5  10  9  Total 272  309  335  Average Permian Basin rig count to U.S. rig count 48.5  % 51.6  % 48.7  % 41 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 labor costs amounted to 28.5% and 30.2% of total costs of service for the years ended December 31, 2025, and 2024, respectively. The decrease in our direct labor costs percentage is driven by the implementation of reactive cost reductions to align our costs with the decrease in customer activity experienced in fiscal year 2025. Expendables. Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our completion services and other operations. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services. Expendable product costs comprised approximately 26.8% and 25.7% of total costs of service for the years ended December 31, 2025, and 2024, respectively. The percentage increase in our expendables was primarily attributable to the impact of general cost inflation. Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental, lease costs on our FORCE® electric-powered hydraulic fracturing fleets, and other miscellaneous operating expenses. Fuel is consumed both in the operation and movement of our equipment. Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs. Capital expenditures to upgrade or extend the useful life of equipment are capitalized and are not included in other direct costs. Other direct costs were 44.7% and 44.1% of total costs of service for the years ended December 31, 2025, and 2024, respectively. The percentage increase in our expendables was primarily attributable to the impact of general cost inflation. 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 expenses/(income) 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 42 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): Hydraulic Fracturing Wireline Cementing Power Generation Reconciling Items Total Year ended December 31, 2025 Service revenue $ 929,210  $ 209,034  $ 130,266  $ 1,538  $ (890) $ 1,269,158  Adjusted EBITDA $ 208,566  $ 41,563  $ 22,011  $ (11,580) $ (52,117) $ 208,443  Depreciation and amortization $ 143,785  $ 22,269  $ 8,098  $ 673  $ 71  $ 174,896  Operating lease expense on FORCE® fleets (1) $ 61,274  $ —  $ —  $ —  $ —  $ 61,274  Capital expenditures incurred $ 69,149  $ 7,922  $ 5,752  $ 198,373  $ —  $ 281,196  Goodwill $ 920  $ —  $ —  $ —  $ —  $ 920  Total assets (2) $ 841,180  $ 162,225  $ 69,396  $ 201,481  $ 16,608  $ 1,290,890  Hydraulic Fracturing Wireline Cementing Power Generation 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 (3) $ 194,557  $ 20,633  $ 8,819  $ —  $ 100  $ 224,109  Property and equipment impairment expense (4) $ 188,601  $ —  $ —  $ —  $ —  $ 188,601  Goodwill impairment expense (5) $ —  $ 23,624  $ —  $ —  $ —  $ 23,624  Operating lease expense on FORCE® fleets (1) $ 47,141  $ —  $ —  $ —  $ —  $ 47,141  Capital expenditures incurred $ 116,257  $ 7,713  $ 9,376  $ —  $ 42  $ 133,388  Goodwill $ 920  $ —  $ —  $ —  $ —  $ 920  Total assets (2) $ 961,485  $ 156,349  $ 73,935  $ —  $ 31,876  $ 1,223,645  Hydraulic Fracturing Wireline Cementing Power Generation 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 (3) $ 194,745  $ 18,762  $ 5,879  $ —  $ 222  $ 219,608  Operating lease expense on FORCE® fleets (1) $ 5,087  $ —  $ —  $ —  $ —  $ 5,087  Capital expenditures incurred $ 294,377  $ 12,203  $ 3,440  $ —  $ —  $ 310,020  Goodwill $ —  $ 23,624  $ —  $ —  $ —  $ 23,624  Total assets (2) $ 1,189,526  $ 198,957  $ 78,475  $ —  $ 13,354  $ 1,480,312  ____________________ (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 consolidated statements of operations. (2)Total assets under “Reconciling Items” comprise of cash on hand, certain property, equipment and operating lease right-of-use assets pertaining to our corporate administrative activities. 43 (3)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 amounts of $12.4 million and $38.7 million from loss on disposal of assets to depreciation for the years ended December 31, 2024 and 2023, respectively. (4)Represents noncash property and equipment impairment expense on our Tier II Units. There was no property and equipment impairment expense for the years ended December 31, 2025 and 2023. (5)Represents noncash impairment of goodwill in our Wireline operating segment. There was no goodwill impairment expense for the years ended December 31, 2025 and 2023. A reconciliation of net (loss) income to Adjusted EBITDA is provided in the table below (in thousands): Year Ended December 31, 2025 2024 2023 Net income (loss) $ 824  $ (137,859) $ 85,634  Depreciation and amortization (1) 174,896  224,109  219,608  Property and equipment impairment expense (2) —  188,601  —  Goodwill impairment expense (3) —  23,624  —  Interest expense 8,238  7,815  5,308  Income tax expense (benefit) 6,997  (31,385) 29,868  Loss (gain) on disposal of assets and businesses, net (1) 12,179  (4,925) 34,293  Stock‑based compensation 16,946  17,288  14,450  Business acquisition contingent consideration adjustments (4,900) (2,600) —  Other (income) expense, net (4) (9,709) (5,531) 9,533  Other general and administrative expense, net (5) 339  1,782  2,969  Retention bonus and severance expense 2,633  2,324  2,297  Adjusted EBITDA $ 208,443  $ 283,243  $ 403,960  ____________________ (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 amounts of $12.4 million and $38.7 million from loss on disposal of assets to depreciation for the years ended December 31, 2024 and 2023, respectively. (2)Represents noncash impairment expense on our Tier II Units. This impairment expense is included in our Hydraulic Fracturing operating segment. (3)Represents noncash impairment of goodwill in our Wireline operating segment. (4)Other income for the year ended December 31, 2025 is primarily comprised of direct payment tax refunds and well service tax refunds (net of advisory fees) totaling $3.3 million, a $2.4 million unrealized gain on short-term investment, interest income from note receivable from sale of business of $1.2 million, adjustments to workers' compensation and general liability insurance premiums of $1.0 million, insurance reimbursements of $0.8 million and $1.0 million of other income. Other income for the year ended December 31, 2024 is primarily comprised of tax refunds (net of advisory fees) totaling $5.0 million and insurance reimbursements of $2.0 million, partially offset by a $2.0 million loss to a customer related to an accidental cementing job failure. Other expense for the year ended December 31, 2023 is primarily comprised of settlement expenses resulting from routine audits and true-up health insurance costs totaling approximately $7.4 million and a $2.5 million unrealized loss on short-term investment. (5)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. 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). Our Power Generation operating segment is shown in the “All Other” category for segment reporting purposes. Year Ended December 31, 2025 Compared to Year Ended December 31, 2024 (in thousands, except percentages) Year Ended December 31, Change 2025 2024 Variance % Revenue Hydraulic Fracturing $ 929,210 $ 1,092,000 $ (162,790) (14.9) % Wireline 209,034 203,182 5,852 2.9  % Cementing 130,266 149,411 (19,145) (12.8) % Power Generation 1,538 — 1,538 100.0  % Elimination of intersegment service revenue (890) (307) (583) (189.9) % Total revenue 1,269,158 1,444,286 (175,128) (12.1) % Cost of services (1) Hydraulic Fracturing 702,593 800,202 (97,609) (12.2) % Wireline 156,472 148,125 8,347 5.6  % Cementing 103,388 117,490 (14,102) (12.0) % Power Generation 6,612 4 6,608 165,200.0  % Elimination of intersegment cost of services (890) (307) (583) (189.9) % Total cost of services 968,175 1,065,514 (97,339) (9.1) % General and administrative expense (2) 107,558 114,323 (6,765) (5.9) % Depreciation and amortization (3) 174,896 224,109 (49,213) (22.0) % Property and equipment impairment expense — 188,601 (188,601) (100.0) % Goodwill impairment expense — 23,624 (23,624) (100.0) % Loss (gain) on disposal of assets and business, net (3) 12,179 (4,925) 17,104 347.3  % Interest expense 8,238 7,815 423 5.4  % Other income, net (9,709) (5,531) (4,178) (75.5) % Income tax expense (benefit) 6,997 (31,385) 38,382 122.3  % Net income (loss) $ 824 $ (137,859) $ 138,683 100.60  % Adjusted EBITDA (4) $ 208,443 $ 283,243 $ (74,800) (26.41) % Adjusted EBITDA margin (4) 16.4  % 19.6  % (3.2) % (16.33) % Net income (loss) margin (5) 0.1  % (9.5) % 9.6  % 101.05  % Hydraulic Fracturing segment results of operations: Revenue $ 929,210 $ 1,092,000 $ (162,790) (14.9) % Cost of services $ 702,593 $ 800,202 $ (97,609) (12.2) % Adjusted EBITDA $ 208,566 $ 270,505 $ (61,939) (22.9) % Adjusted EBITDA margin (6) 22.4  % 24.8  % (2.4) % (9.7) % ____________________ (1)    Exclusive of depreciation and amortization. 45 (2)    Inclusive of stock‑based compensation. (3)    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 $12.4 million from loss on disposal of assets to depreciation for the year ended December 31, 2024. (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 measure calculated in accordance with GAAP, please read “How We Evaluate Our Operations.” (5)    Net loss margin reflects our net loss as a percentage of our revenue. (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 revenues for the Hydraulic Fracturing segment. Revenues.  Revenues decreased 12.1%, or $175.1 million, to $1,269.2 million for the year ended December 31, 2025, as compared to $1,444.3 million for the year ended December 31, 2024. Revenue by reportable segment was as follows: Hydraulic Fracturing. Our Hydraulic Fracturing segment revenues decreased 14.9%, or $162.8 million for the year ended December 31, 2025, as compared to the year ended December 31, 2024. The decrease was primarily attributable to decreased customer activity, reduced customer pricing, and idling of fleets, partially offset by the addition of AquaProp's operations in May 2024, which resulted in a $41.9 million increase in revenues during fiscal year 2025 due to the impact of AquaProp’s operations for the full year ended December 31, 2025 compared to only 215 days of activity during fiscal year 2024. Intersegment revenues totaled $0.9 million and $0.3 million for the years ended December 31, 2025 and 2024, respectively. Intersegment revenues were derived from our Wireline, Cementing and Power Generation segments for the year ended December 31, 2025, and from our Wireline segment for the year ended December 31, 2024. Wireline. Our Wireline segment revenues increased 2.9%, or $5.9 million for the year ended December 31, 2025, as compared to the year ended December 31, 2024. The increase was primarily attributable to increased customer activity and utilization. Cementing. Our Cementing segment revenues decreased 12.8%, or $19.1 million for the year ended December 31, 2025, as compared to the year ended December 31, 2024. The decrease was primarily attributable to the sale of our cementing business located in Vernal, Utah in November 2024 which contributed $22.3 million in revenues during fiscal year 2024, partially offset by increases resulting from synergies gained with customers after the acquisition of Par Five Energy Services LLC. Power Generation. Our Power Generation segment revenue was $1.5 million for the year ended December 31, 2025. Our Power Generation segment began revenue generating activities during the third quarter of fiscal year 2025. Cost of Services.  Cost of services decreased 9.1%, or $97.3 million, to $968.2 million for the year ended December 31, 2025, from $1,065.5 million during the year ended December 31, 2024. Cost of services by reportable segment was as follows: Hydraulic Fracturing. Our Hydraulic Fracturing segment cost of services decreased $97.6 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024. As a percentage of hydraulic fracturing segment revenues, Hydraulic Fracturing cost of services was 75.6% for the year ended December 31, 2025, as compared to 73.3% for the year ended December 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 resulted in a $33.8 million increase in cost of services during fiscal year 2025. Wireline. Our Wireline segment cost of services increased 5.6%, or $8.3 million for the year ended December 31, 2025, as compared to the year ended December 31, 2024 due to increased customer activity and the impact of general cost inflation. Intersegment cost of services, consisting of cost of services incurred to our Hydraulic Fracturing segment, totaled $0.7 million and $0.3 million for the years ended December 31, 2025 and 2024, respectively. Cementing. Our Cementing cost of services decreased 12.0%, or $14.1 million for the year ended December 31, 2025, as compared to the year ended December 31, 2024. The decrease was primarily attributable to the sale of our cementing business located in Vernal, Utah in November 2024 which incurred $14.7 million in cost of services during fiscal year 2024. Intersegment cost of services, consisting of cost of services incurred to our Hydraulic Fracturing segment, totaled $0.1 million and $0 for the years ended December 31, 2025 and 2024, respectively. 46 Power Generation. Our Power Generation segment cost of services was $6.6 million for the year ended December 31, 2025. Our Power Generation segment began revenue generating activities during the third quarter of fiscal year 2025. Intersegment cost of services, consisting of cost of services incurred to our Hydraulic Fracturing segment, totaled $0.1 million and $0 for the years ended December 31, 2025 and 2024, respectively. General and Administrative Expenses.  General and administrative expenses decreased 5.9% or $6.7 million, to $107.6 million for the year ended December 31, 2025, as compared to $114.3 million for the year ended December 31, 2024. The net decrease was primarily attributable to a $4.5 million decrease in professional fees, a $2.3 million increase in business acquisition contingent consideration adjustments, a $2.0 million decrease in dues and subscriptions, a $1.6 million decrease in transaction expenses and a $0.4 million net decrease in other general and administrative expenses, partially offset by a $4.1 million increase in payroll. Excluding nonrecurring and noncash items (i.e., stock-based compensation of $16.9 million, retention bonuses and severance expenses of $2.7 million and legal settlements (net of insurance reimbursements) of $0.3 million, partially offset by business acquisition contingent consideration adjustments of $4.9 million), general and administrative expenses were $92.6 million for the year ended December 31, 2025, as compared to $95.5 million for the year ended December 31, 2024. Depreciation and Amortization.  Depreciation and amortization decreased 22.0%, or $49.2 million, to $174.9 million for the year ended December 31, 2025, as compared to $224.1 million for the year ended December 31, 2024. The decrease was primarily attributable to assets fully depreciating and a reduction in the cost basis of Tier II Units impaired in the third quarter of fiscal year 2024, partially offset by the addition of AquaProp's operations in May 2024 which resulted in a $2.7 million increase in depreciation and amortization. Property and Equipment Impairment Expense.  There was no impairment expense during the year ended December 31, 2025. During the year ended December 31, 2024, we recorded a noncash 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. Goodwill Impairment Expense.  There was no goodwill impairment expense during the year ended December 31, 2025. During the year ended December 31, 2024, we recorded goodwill impairment expense of $23.6 million in our Wireline reportable segment. Loss (Gain) on Disposal of Assets and Business.  Loss on the disposal of assets increased 347.3%, or $17.1 million, to $12.2 million for the year ended December 31, 2025, as compared to a gain on the disposal of assets and business of $4.9 million for the year ended December 31, 2024. The increase was primarily attributable to losses incurred during fiscal year 2025 from the sale of certain Tier II hydraulic fracturing equipment and a $8.2 million gain related to the sale of our cementing business located in Vernal, Utah, during fiscal year 2024. Interest Expense.  Interest expense increased to $8.2 million for the year ended December 31, 2025, as compared to $7.8 million for the year ended December 31, 2024. The increase was primarily attributable to the addition of loans under the Caterpillar Equipment Loan Agreement (as defined below) to support the purchase of certain mobile natural gas-fueled power generation equipment during the year ended December 31, 2025. Other Income.  Other income was approximately $9.7 million for the year ended December 31, 2025, as compared to other income of $5.5 million for the year ended December 31, 2024. Other income for the year ended December 31, 2025 is primarily comprised of direct payment tax refunds and well service tax refunds (net of advisory fees) totaling $3.3 million, a $2.4 million unrealized gain on short-term investment, interest income from note receivable from sale of business of $1.2 million, adjustments to workers' compensation and general liability insurance premiums of $1.0 million, insurance reimbursements of $0.8 million and $1.0 million of other income. Other income for the year ended December 31, 2024 is primarily comprised of tax refunds (net of advisory fees) totaling $5.0 million and insurance reimbursements of $2.0 million, partially offset by a $2.0 million loss to a customer related to an accidental cementing job failure. Income Taxes.  Total income tax expense was $7.0 million resulting in an effective tax rate of 89.5% for the year ended December 31, 2025, as compared to income tax benefit of $31.4 million resulting in an effective tax rate of 18.5% for the year ended December 31, 2024. The change in income tax expense recorded during the year ended December 31, 2025, compared to the change in income tax expense recorded during the year ended December 31, 2024, is primarily attributable to the difference in the impact of nondeductible expenses, state taxes, and valuation allowances on the pre-tax income for fiscal year 2025, as compared to fiscal year 2024. 47 Liquidity and Capital Resources Our liquidity is currently provided by (i) existing cash balances, including proceeds from the 2026 Common Stock Offering, (ii) operating cash flows, (iii) borrowings under our ABL Credit Facility (as defined below) and (iv) borrowings under our Caterpillar Equipment Loan Agreement (as defined below). See “Credit Facility and Other Financing Arrangements” below. Additionally, on December 29, 2025, we entered into the Stonebriar Equipment Lease Facility to support the lease of certain mobile power generation equipment, including turbine generator sets along with auxiliary equipment, for our PROPWRSM business line, and in January 2026, we received approximately $163.3 million from the 2026 Common Stock Offering. Our cash is primarily used to fund our operations, support growth opportunities, fund share repurchases under our share repurchase program and satisfy future debt repayments and lease payments. Our Borrowing Base (as defined below), under our ABL Credit Facility, as 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 customers for our services, and the amount outstanding in connection with the advance payments as of December 31, 2025 was $8.1 million, which does not include any restricted cash. As of December 31, 2025, our borrowings under our ABL Credit Facility were $45.0 million, our borrowings under our Caterpillar Equipment Loan Agreement were $77.6 million and our total liquidity was $205.4 million, consisting of cash and cash equivalents of $91.3 million and $114.1 million of availability under our ABL Credit Facility. As of January 31, 2026, our borrowings under our ABL Credit Facility were $45.0 million, our borrowings under our Caterpillar Equipment Loan Agreement were $86.9 million and our total liquidity was $325.0 million, consisting of cash and cash equivalents of $236.5 million and $88.5 million of availability under our ABL Credit Facility. In May 2025, the Company's board of directors (the “Board”) approved a further extension to the share repurchase program initially authorized on May 17, 2023. As extended, the program permits the repurchase of up to $200 million of the Company’s common stock through December 31, 2026. The shares may be repurchased from time to time in open market transactions, block trades, accelerated share repurchases, privately negotiated transactions, derivative transactions or otherwise, certain of which may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act, as amended, in compliance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the 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 December 2026. During the year ended December 31, 2025, the Company made no share repurchases under the share repurchase program as it prioritized the launch and scaling of its PROPWRSM business line. The Company intends to continue to prioritize investing in its PROPWRSM business line in the near future. As of December 31, 2025, $89.2 million remained authorized for future repurchases of common stock under the share repurchase program. In October 2025, the Company sold its short-term investment in 2.6 million common shares of STEP Energy Services Ltd. (“STEP”), which it received in 2022 as part of the consideration for its sale of its coiled tubing assets to STEP. The Company received $9.4 million in proceeds and recognized a $0.8 million loss on sale of assets from the sale of this investment. In December 2025, the Company received $11.9 million in proceeds as full repayment of the outstanding balance and accrued interest on its note receivable from Big 4 Services LLC (“Big 4”). The Company received this note receivable from Big 4 on November 1, 2024 as consideration for the sale of its cementing business located in Vernal, Utah. In January 2026, the Company sold 17.3 million shares of its common stock under an underwritten public offering for $10.00 per share, pursuant to an effective shelf registration statement on Form S-3 filed with the SEC. The Company received approximately $163.3 million in net proceeds from this sale after deducting underwriting discounts and commissions and estimated offering expenses. The Company intends to use the net proceeds from this sale for general corporate purposes, including to fund growth capital for additional power generation equipment. 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 48 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, 2025 and 2024, respectively. (in thousands) Year Ended December 31, 2025 2024 Net cash provided by operating activities $ 231,607  $ 252,295  Net cash used in investing activities $ (149,811) $ (155,099) Net cash used in financing activities $ (40,905) $ (80,107) Operating Activities Net cash provided by operating activities was $231.6 million for the year ended December 31, 2025, as compared to $252.3 million for the year ended December 31, 2024. The net decrease of $20.7 million was primarily attributable 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 $149.8 million for the year ended December 31, 2025, from $155.1 million for the year ended December 31, 2024. The net decrease was primarily attributable to the acquisition of AquaProp which resulted in a $21.0 million net cash outflow for the year ended December 31, 2024, a $17.3 million increase in proceeds from sale of assets (including $9.4 million from the sale of the Company’s short-term investment discussed in “Note 5. Fair Value Measurements”) and $13.0 million in proceeds from note receivable from sale of business further discussed in “Note 16. Related Party Transactions,” partially offset by a $46.0 million increase in capital expenditures primarily related to our PROPWRSM power generation business. The following table reconciles our capital expenditures paid to capital expenditures incurred for the periods indicated: (in thousands) Year Ended December 31, 2025 2024 Capital expenditures paid (1) $ 186,316  $ 140,297  Less: Capital expenditures included in accounts payable and accrued liabilities - beginning of period (14,695) (21,604) Add: Capital expenditures included in accounts payable and accrued liabilities - end of period 28,095  14,695  Add: Capital expenditures related to financed equipment purchases 81,130  —  Add: Capital expenditures financed by operating lease landlord 350  —  Capital expenditures incurred (1) $ 281,196  $ 133,388  ____________________ (1)This table reconciles cash basis capital expenditures reported in the Company's consolidated statements of cash flows to accrual basis capital expenditures reported in "Note 11. - Reportable Segment Information" and below. 49 The following table summarizes our capital expenditures incurred by reportable segment for the periods indicated: (in thousands) Year Ended December 31, 2025 2024 Reportable Segments: Hydraulic Fracturing $ 69,149  $ 116,257  Wireline 7,922  7,713  Cementing 5,752  9,376  Power Generation 198,373  —  Reconciling Items (1) —  42  Total capital expenditures incurred (2) $ 281,196  $ 133,388  _________________ (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 decreased to $40.9 million for the year ended December 31, 2025, compared to $80.1 million for the year ended December 31, 2024. The net decrease was primarily driven by a $59.1 million decrease in share repurchases, partially offset by a $6.8 million increase in payment of business acquisition deferred cash consideration, a $3.6 million increase in repayments of equipment financing term loans, a $3.5 million increase in repayments of insurance financing, a $2.8 million increase in payment of financing origination and debt issuance costs and a $2.3 million increase in tax withholdings paid for net settlement of equity awards. Credit Facility and Other Financing Arrangements The Company is a party to the ABL Credit Facility that provides for borrowing capacity of up to $225.0 million (subject to the Borrowing Base limit), and matures on June 2, 2028. ABL Credit Facility: Effective December 26, 2025, 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, as amended in December 2025 and as may be amended further, the “ABL Credit Facility”). The amendment increased the debt basket for capital/finance leases, purchase money debt, and other similar financing facilities to $425.0 million. The Borrowing Base as of December 31, 2025, was approximately $167.7 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 excluding certain mobile natural gas-fueled power generation equipment purchased under a financing arrangement. 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, 2025, was 6.29%. As of December 31, 2025, and 2024, we had outstanding borrowings under our ABL Credit Facility of $45.0 million and $45.0 million, respectively. 50 Caterpillar Equipment Loan Agreement: On April 2, 2025, we entered into a financing arrangement and on February 6, 2026, we entered into an amendment to this financing arrangement with Caterpillar Financial Services Corporation (collectively, the “Caterpillar Equipment 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 PROPWRSM business line, under which the lender, Caterpillar Financial Services Corporation (an affiliate of the equipment manufacturer), will fund progress payments beyond the initial down payment on the equipment for a maximum total available amount of $157.3 million and provide us interim loans in connection with each progress payment made on our behalf. Such interim loans will accrue interest at a floating rate per annum based on SOFR, plus a 3.85% margin, plus any increase or minus any decrease in the Bloomberg Industrial Single A Total Return Index since November 15, 2024. Such interim loans will be combined and converted to a term loan for each unit of equipment after the final progress payment is funded for such unit. Interest on interim loans is payable on a monthly basis until conversion to term loans. Each term loan will accrue interest at a fixed rate per annum based on the three-year U.S Treasury rate as of the date of conversion of interim loans to the term loan for each unit of equipment, plus a 3.70% margin, plus any increase or minus any decrease in the Bloomberg Industrial Single A Total Return Index since November 15, 2024 and will be payable in equal monthly installments over a period not to exceed five years. Each loan will be secured on a first lien basis by equipment collateral and support documents, casualty proceeds and other proceeds or products related thereto, and any proceeds from the equipment loan must be used for payment or reimbursement for the equipment subject to such loan. Each loan will be fully and unconditionally guaranteed by the guarantors set forth in the Caterpillar Equipment Loan Agreement. The weighted average interest rate on our interim loans (short-term loans) as of December 31, 2025 was 7.69%. The weighted average interest rate on our term loans (long-term loans) for the year ended December 31, 2025 was 7.34%. Under the Caterpillar Equipment Loan Agreement, we have incurred interim loans and term loans with outstanding amounts of $2.1 million and $75.4 million, respectively, as of December 31, 2025, related to funding for equipment under construction and equipment received. See “Note 8. Interim and Long-Term Debt.” The financed payments from the lender (an affiliate of the equipment manufacturer) are presented as non-cash investing and financing activities within the “Supplemental Disclosure of Non-Cash Investing and Financing Activities” section of our consolidated statements of cash flows. The repayments of term loans are presented as cash outflows under cash flows from financing activities in our consolidated statements of cash flows. Stonebriar Equipment Lease Facility. On December 29, 2025, ProPetro Energy Solutions, LLC (“PROPWR”), a wholly owned subsidiary of the Company, entered into an Interim Funding Agreement and a Master Lease Agreement with Stonebriar for the right, but not the obligation, to fund up to $350.0 million of purchases of power generator equipment . Under the Interim Funding Agreement, Stonebriar provides funding to finance down payments and progress payments owing to equipment suppliers. Monthly rent under the Interim Funding Agreement is based on the unpaid balance of the aggregate amounts advanced under the Interim Funding Agreement and not yet converted to a lease schedule under the Master Lease Agreement, times a per annum lease rate factor equal to sum of 1-Month SOFR plus 6.25%. Upon delivery and acceptance of a power generator, amounts outstanding under the Interim Funding Agreement with respect to such equipment are converted into a lease schedule under the Master Lease Agreement. Stonebriar will hold legal title to such leased equipment. The lease term for each item of equipment will be 84 months, and the rental payment amounts will be based on the equipment cost times a lease rate factor set forth in the applicable lease schedule. PROPWR will have certain early termination and purchase options with respect to the leased equipment at various points during the lease, as set forth in the Master Lease Agreement and related lease schedule for such equipment. Upon exercise of such rights and payment of the required amounts, PROPWR would acquire legal title to such equipment. Off-Balance Sheet Arrangements We had no material off balance sheet arrangements as of December 31, 2025. Capital Requirements, Future Sources and Use of Cash Capital expenditures incurred were $281.2 million during the year ended December 31, 2025, as compared to $133.4 million during the year ended December 31, 2024. The significant portion of our total capital expenditures incurred during the year ended December 31, 2025 were for our Power Generation segment totaling $198.4 million including $81.1 million of financed equipment purchases for this business, and maintenance capital expenditures. Our future material use of cash will be to fund our capital expenditures and to repay debt and other financing obligations, if any. Although we intend to prioritize investing in our PROPWRSM business line in the near future, we may also use material amounts of cash to repurchase shares under our share repurchase program. Capital expenditures for 2026 are projected to be primarily related to capital expenditures to purchase power generation equipment, costs to extend the useful life of our existing completion services assets, costs to convert some existing equipment to lower emissions equipment, potential buyout of leased FORCE® electric-powered hydraulic fracturing fleets, strategic purchases and other ancillary equipment purchases, subject to 51 market conditions and customer demand. Our future capital expenditures depend on our projected operational activity, emission requirements and planned conversions to lower emissions equipment and demand for our power generation services, among other factors, which could vary significantly throughout the year. Based on our current plan and projected activity levels for 2026, we expect our capital expenditures to range between $390 million and $435 million, which includes approximately $140 million to $160 million for our completion services business, including approximately $40 million to $50 million related to lease buyouts for a portion of our FORCE® electric-powered hydraulic fracturing fleets. Additionally, we expect to incur approximately $250 million to $275 million in 2026 for our PROPWRSM business line. We entered into contractual arrangements with an equipment manufacturer to purchase mobile natural gas-fueled power generation equipment, including turbine generator sets along with auxiliary equipment, for our PROPWRSM business line, with a total cost of $186.6 million. The total remaining commitment (after initial down payment and financed payments) under these arrangements as of December 31, 2025 was $87.1 million, of which $76.1 million will be financed under the Caterpillar Equipment Loan Agreement. We expect to receive the remaining equipment currently on order under these arrangements from the first quarter through the third quarter of fiscal year 2026. We also entered into contractual arrangements with other equipment manufacturers to purchase additional power generation and auxiliary equipment for our PROPWRSM business line, with a total remaining commitment of approximately $203.0 million. We expect to receive the remaining equipment currently on order under these arrangements from the middle of fiscal year 2026 through the end of fiscal year 2027. 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 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. The Company may also decide to exercise its buyout options on its leased FORCE® electric-powered hydraulic fracturing fleets at the end of their leases. We anticipate our capital expenditures will be funded by existing cash, including proceeds from the 2026 Common Stock Offering, cash flows from operations, the Caterpillar Equipment Loan Agreement, other financing arrangements including the Stonebriar Equipment Lease Facility, and 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, 2025: (in thousands) Period Total  1 year or less More than 1 year ABL Credit Facility (1) $ 45,000  $ —  $ 45,000  Equipment financing interim loans (2) 2,135  2,135  —  Equipment financing term loans (3) 90,402  19,329  71,073  Operating leases (4)(5) 84,984  47,426  37,558  Finance lease (6) 12,767  12,767  —  Equipment purchase commitments (7) 290,122  225,984  64,138  Unused commitment fee on equipment lease facility (8) 1,750  —  1,750  Total $ 527,160  $ 307,641  $ 219,519  ____________________ (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 or future interest rates to be changed. However, assuming a weighted average interest rate of 6.29%, and that our ABL Credit Facility debt balance remains the same, our estimated annual interest payment will be $2.8 million. (2)Excludes interest expense because obligations under our equipment financing interim loans have floating rates of interest and we cannot determine with accuracy the timing of conversion to term loans, repayments or future interest rates to be changed. 52 (3)Includes interest expense since obligations under our equipment financing term loans have fixed rates of interest and predetermined repayment schedules. (4)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). (5)Includes our leases for FORCE® electric-powered hydraulic fracturing fleets (312,000 HHP). (6)Finance lease for certain power generation equipment (70 megawatts) to support electric-powered hydraulic fracturing equipment. (7)Represents contractual commitments with equipment manufacturers to purchase power generation and auxiliary equipment for our PROPWRSM business line (see “Note 18. Commitments and Contingencies” in the financial statements for additional disclosures). (8)Represents the maximum amount we may owe under the Stonebriar Equipment Lease Facility described in “Note 17. Leases” for any unused portion of the lease facility. 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 minimum volumes or a fixed price per ton of unpurchased volumes. Our existing agreements with the Sand Suppliers expire on May 31, 2029. 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 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 estimates that we believe are critical to our financial statements since these estimates require a high degree of complexity and judgment, and that we believe are critical to understanding our operations. Depreciation and Amortization Our property and equipment are recorded at cost, less accumulated depreciation. The estimated useful lives and salvage values of our property and equipment are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology. 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 $14.7 million impact on pre-tax income during the year ended December 31, 2025. Intangible assets, other than goodwill, consist of trademark/trade name, customer relationships and favorable contracts. The estimated useful lives of these intangible assets 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. 53 Impairment of Long-Lived Assets We review our long‑lived assets, other than goodwill, for impairment whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. For the impairment testing on long-lived assets, other than goodwill, a long-lived asset is grouped at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Estimated future undiscounted cash flows expected to result from the use and eventual disposition of the asset group are compared to the carrying amount of the underlying assets. An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable to the asset group 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 assumptions in our cash flow forecasts are our estimated equipment utilization and profitability. These assumptions are uncertain in that they are 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. During the years ended December 31, 2025 and 2023, we did not recognize any impairment of our long-lived assets. During the year ended December 31, 2024, we recognized 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. 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. We believe the valuation allowance is a critical accounting estimate because it is susceptible to change from period to period, requires assumptions about our future income over the lives of the deferred tax assets, and because the impact of increasing or decreasing the valuation allowance is potentially material to our results of operations. In determining our need for a valuation allowance as of December 31, 2025, 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 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.