FORM 10-K

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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  ý  No ¨

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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ý

The number of the registrant’s common shares, par value $0.001 per share, outstanding at March 8, 2024, was 107,567,074.

This Annual Report on Form 10-K (the "Annual Report") contains forward‑looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts contained in this Form 10-K are forward-looking statements. Forward-looking statements are all statements other than statements of historical fact, and given our expectations or forecasts of future events as of the effective date of this Form 10-K. Words such as "may," "could," "plan," "project," "budget," "predict," "pursue," "target," "seek," "objective," "believe," "expect," "anticipate," "intend," "estimate," "will," "should" and similar expressions are generally used to identify forward-looking statements. These statements include, but are not limited to, statements about our business strategy, industry, future profitability, future capital expenditures, our fleet conversion strategy and our share repurchase program. Such statements are subject to risks and uncertainties. Many of which are difficult to predict and generally beyond our control, that could cause actual results to differ materially from those implied or projected by the forward-looking statements. Factors that could cause our actual results to differ materially from those contemplated by such forward‑looking statements include:

•changes in general economic and geopolitical conditions, including higher interest rates, the rate of inflation and a potential economic recession;

•central bank policy actions, bank failures and associated liquidity risks and other factors;

•the severity and duration of any world events and armed conflict, including the Russian-Ukraine war, conflicts in the Israel-Gaza region and associated repercussions to supply and demand for oil and gas and the economy generally;

•the actions taken by the members of the Organization of the Petroleum Exporting Countries ("OPEC") and Russia (together with OPEC and other allied producing countries, "OPEC+") with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;

•actions taken by the current government, such as executive orders or new regulations, that may negatively impact the future production of oil and natural gas in the United States and may adversely affect our future operations;

•the level of production and resulting market prices for crude oil, natural gas and other hydrocarbons;

•the effects of existing and future laws and governmental regulations (or the interpretation thereof) on us, our suppliers and our customers;

•cost increases and supply chain constraints related to our services, including any delays and/or supply chain disruptions due to increased hostilities in the Middle East;

•competitive conditions in our industry;

•our ability to attract and retain employees;

•changes in the long-term supply of, and demand for, oil and natural gas;

•actions taken by our customers, suppliers, competitors and third-party operators and the possible loss of customers or work to our competitors;

•technological changes, including lower emissions oilfield service equipment and similar advancements;

•changes in the availability and cost of capital;

•our ability to successfully implement our business plan, including execution of potential mergers and acquisitions;

•large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;

•the effects of consolidation on our customers or competitors;

•the price and availability of debt and equity financing (including increasing interest rates) for us and our customers;

•our ability to complete growth projects on time and on budget;

•increases in tax rates or types of taxes enacted that specifically impact E&P and related operations resulting in changes in the amount of taxes owed by us;

•regulatory and related policy actions intended by federal, state and/or local governments to reduce fossil fuel use and associated carbon emissions, or to drive the substitution of renewable forms of energy for oil and gas, may over time reduce demand for oil and gas and therefore the demand for our services;

•new or expanded regulations that materially limit our customers’ access to federal and state lands for oil and gas development, thereby reducing demand for our services in the affected areas;

•growing demand for electric vehicles that result in reduced demand for gasoline and therefore the demand for our services;

•our ability to successfully implement technological developments and enhancements, including our new Tier IV Dynamic Gas Blending ("DGB") dual-fuel and FORCESM electric-powered hydraulic fracturing equipment, and other lower-emissions equipment we may acquire or that may be sought by our customers;

•the projected timing, purchase price and number of shares purchased under our share repurchase program, the sources of funds under the repurchase program and the impacts of the repurchase program;

•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control, such as fires, which risks may be self-insured, or may not be fully covered under our insurance programs;

•exposure to cyber-security events which could cause operational disruptions or reputational harm;

•acts of terrorism, war or political or civil unrest in the United States or elsewhere; and

•the effects of current and future litigation.

Unless the context indicates otherwise, all references to "ProPetro Holding Corp.," "the Company," "we," "our" or "us" or like terms refer to ProPetro Holding Corp. and its consolidated subsidiaries, ProPetro Services, Inc. and Silvertip Completion Services Operating, LLC.

•Our business and financial performance depends on the historically cyclical oil and natural gas industry and particularly on the level of capital spending and exploration and production (“E&P”) activity within the United States and in the Permian Basin, and a decline in prices for oil and natural gas may cause fluctuation in operating results or otherwise have an adverse effect on our revenue, cash flows, profitability and growth.

•The cyclical nature of the oil and natural gas industry may cause our operating results to fluctuate.

•The majority of our operations are located in the Permian Basin, making us vulnerable to risks associated with operating in one major geographic area.

•The Inflation Reduction Act of 2022 ("IRA 2022") and actions taken by the United States and other countries on climate change or to transition away from fossil fuels could accelerate the transition to a low carbon economy and could impose new costs on our customers’ operations.

•The COVID-19 pandemic has negatively impacted crude oil prices and demand for our products and services in recent years, and may negatively impact crude oil prices and demand for our products and services in the future.

•Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.

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

•Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.

•Restrictions in our ABL Credit Facility (as defined herein) and any future financing agreements may limit our ability to finance future operations or capital needs or capitalize on potential acquisitions and other business opportunities.

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

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

•We may grow through acquisitions and our failure to properly plan and manage those acquisitions may adversely affect our performance.

•Reliance upon a few large customers may adversely affect our revenue and operating results.

•We face significant competition that may cause us to lose market share, and competition in our industry has intensified during the recent industry downturn.

•We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our business, results of operations and financial conditions.

•Our business depends upon the ability to obtain specialized equipment, parts and key raw materials, including sand and chemicals, from third‑party suppliers, and we may be vulnerable to delayed deliveries and future price increases.

•We may be required to pay fees to certain of our sand suppliers (the “Sand Suppliers”) based on minimum volumes under long-term contracts regardless of actual volumes received.

•We rely on a few key employees whose absence or loss could adversely affect our business.

•If we are unable to employ a sufficient number of skilled and qualified workers, our capacity and profitability could be diminished and our growth potential could be impaired.

•We are subject to environmental laws and regulations, and future compliance, claims, and liabilities relating to such matters may have a material adverse effect on our results of operations, financial position or cash flows.

•Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.

•Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

•Increased attention to environmental, social and governance (“ESG”) matters, conservation measures, commercial development and technological advances could reduce demand for oil and natural gas and our services.

•Certain of our completion services, particularly our hydraulic fracturing services, are substantially dependent on the availability of water. Restrictions on our or our customers’ ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

•Our ability to use our net operating loss carryforwards (“NOLs”) may be limited.

•Changes to applicable tax laws and regulations or exposure to additional income tax liabilities could adversely affect our operating results and cash flows.

Risks Inherent to an Investment in our Common Stock

•We have identified a material weakness in our internal control over financial reporting with regard to segregation of certain accounting duties and management review controls. We may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may result in material misstatements of our financial statements, cause us to fail to meet our reporting obligations, investors may lose confidence in our financial reporting, and our stock price may decline as a result.

•Certain provisions of our certificate of incorporation, and bylaws, as well as Delaware law, may discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

•Our business could be negatively affected as a result of the actions of activist shareholders.

•Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to pursue actions in another judicial forum for disputes with us or our directors, officers, employees or agents.

•There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.

We are a leading integrated oilfield service company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline, and other complementary oilfield completion services to leading upstream oil and gas companies engaged in the 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.

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. Par Five’s business complements our existing cementing business and enables us to serve both the Midland and Delaware Basins of the Permian Basin.

Effective September 1, 2022, we disposed of our coiled tubing assets to STEP Energy Services Ltd. ("STEP") and shut down our coiled tubing operations. We received approximately $2.8 million in cash and 2.6 million common shares of STEP, valued at $11.8 million, as consideration. Upon the sale of our coiled tubing assets, we recorded a loss on sale of $13.8 million.

Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including upstream and oilfield service companies. As a result, we are working with our customers and equipment manufacturers to transition our equipment to a lower emissions profile. Currently, a number of lower emission solutions for pumping equipment, including Tier IV DGB dual-fuel, FORCESM electric, direct drive gas turbine and other technologies have been developed, and we expect additional lower emission solutions will be developed in the future. We are continually evaluating these technologies and other investment and acquisition opportunities that would support our existing and new customer relationships. The transition to lower emissions equipment is quickly evolving and will be capital intensive. Over time, we may be required to convert substantially all of our conventional Tier II equipment to lower emissions equipment. We have transitioned our hydraulic fracturing available equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022 and 60% in 2023, and expect to increase to approximately 65% by the end of the first half of 2024. 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.

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.

We have historically conducted our business through four operating segments: hydraulic fracturing, wireline, cementing and coiled tubing. Prior to the fourth quarter of fiscal year 2023, our operating segments met the aggregation criteria and were aggregated into the “Completion Services” reportable segment and our coiled tubing operations (which were divested in September 2022) were shown in the “All Other” category. Effective as of the fourth quarter of fiscal year 2023, we revised our segment reporting as we determined that our three operating segments no longer met the criteria to be aggregated. Our Hydraulic Fracturing and Wireline operating segments meet the criteria of a reportable segment. Our cementing and our divested coiled tubing segments do not meet the reportable segment criteria and are included within the “All Other” category. Prior period segment information has been revised to conform to our current presentation. For additional financial information on our reportable segments presentation, please see reportable segment information in Part II - Item 8, "Financial Statements and Supplementary Data."

We provide hydraulic fracturing services to E&P companies in the Permian Basin. These services are intended to optimize hydrocarbon flow paths during the completion phase of horizontal shale wellbores. We have significant expertise in multi‑stage fracturing of horizontal oil‑producing wells in unconventional geological formations. Our total available hydraulic horsepower ("HHP") at December 31, 2023 was 1,461,500 HHP, which was comprised of 452,500 HHP of our Tier IV DGB dual-fuel equipment, 144,000 HHP of FORCESM electric-powered equipment and 865,000 HHP of conventional Tier II equipment. An individual fleet could 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 Simul-Frac, which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in 2021 and 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB dual-fuel equipment, and to purchase new Tier IV DGB dual-fuel equipment. As such, we entered into conversion and purchase agreements with our equipment manufacturers for a total of 452,500 HHP of Tier IV DGB dual-fuel equipment and as of December 31, 2023, we have received all of the converted and new Tier IV DGB dual-fuel equipment. In 2022, we entered into three-year electric fleet leases for a total of four FORCESM electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet. As of December 31, 2023, we have received 144,000 HHP of FORCESM electric-powered equipment. We currently expect to receive the remaining equipment associated with the second and third fleets and all equipment associated with the fourth fleet in the first half of 2024. We have entered into contracts with customers for the use of two of our FORCESM electric-powered hydraulic fracturing fleets to provide committed services for a period of up to three years.

We believe that our cementing segment provides an organic growth opportunity for us to expand our service offerings within our existing customer base. We currently have 40 cementing units.

Our customers consist primarily of oil and natural gas producers in North America. Our top five customers accounted for approximately 63.2%, 84.0% and 85.7% of our revenue, for the years ended December 31, 2023, 2022 and 2021, respectively. For the year ended December 31, 2023, Endeavor Energy Resources and XTO Energy accounted for 19.7% and 18.2%, respectively, of total revenue. No other customer accounted for more than 10% of our total revenue for the year ended December 31, 2023. There have been many recent mergers and acquisitions in the oil and gas industry. In October 2023, Pioneer Natural Resources USA, Inc. (“Pioneer”) entered into a merger agreement with Exxon Mobil Corporation. Mergers and acquisitions involving our customers could negatively impact our future business with them or positively impact our business by providing us access to potential new customers.

On March 31, 2022, we entered into an amended and restated pressure pumping services agreement (the "A&R Pressure Pumping Services Agreement") with Pioneer, which was initially entered into in connection with our purchase of certain pressure pumping assets and real property from Pioneer and Pioneer Pumping Services, LLC (the "Pioneer Pressure Pumping Acquisition"). The A&R Pressure Pumping Services Agreement expired at the conclusion of its term and was replaced by the Fleet One Agreement and the Fleet Two Agreement described below.

Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See "Risk Factors" for a description of certain risks associated with our insurance policies.

Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, and occupational health and safety. Numerous federal, state and local governmental agencies issue regulations that often require difficult and costly compliance measures that could carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may, for example, restrict the types, quantities and concentrations of various substances that can be released into the environment, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas and other protected areas, or require action to prevent or remediate pollution from current or former operations. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental, health and safety laws and regulations occur frequently, and any changes that result in more stringent and costly requirements could materially adversely affect our operations and financial position. For example, following the passage of laws such as the IRA 2022, it is possible that our operations may be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing and wireline, permitting and greenhouse gases ("GHG") emissions. We have not experienced any material adverse effect from compliance with current requirements; however, this trend may not continue in the future.

Waste Handling. We handle, transport, store and dispose of wastes that are subject to the Resource Conservation and Recovery Act ("RCRA") and comparable state laws and regulations, which affect our activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain petroleum production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Moreover, the U.S. Environmental Protection Agency ("EPA") or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or recategorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to recategorize certain oil and natural gas exploration, development and production wastes as hazardous wastes. Several environmental organizations have also petitioned the EPA to modify existing regulations to recategorize certain oil and natural gas exploration, development and production wastes as hazardous. Any such changes in these laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas E&P wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund") and analogous state laws generally impose liability without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Liability for the costs of removing or remediating previously disposed wastes or contamination, damages to natural resources, the costs of conducting certain health studies, amongst other things, is strict and joint and several. In the course of

NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials ("NORM") associated with oil and gas deposits and, accordingly, may result in the generation of wastes and other materials containing NORM. NORM exhibiting levels of radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements.

Water Discharges. The Clean Water Act, Safe Drinking Water Act, Oil Pollution Act and analogous state laws and regulations impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Also, spill prevention, control and countermeasure plan requirements require appropriate containment berms and similar structures to help prevent the contamination of regulated waters.

Air Emissions. The Clean Air Act ("CAA") and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other emissions control requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants from specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These and other laws and regulations may increase the costs of compliance for some facilities where we operate. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects.

Climate Change. In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recently passed laws such as the IRA 2022 advance numerous climate-related objectives. Additionally, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of certain pollutants from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the Department of Transportation ("DOT"), implementing GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, the EPA has recently finalized rules covering the standards of performance for methane and volatile organic compounds emissions for oil and gas facilities, including leak detection, monitoring and repair, and a "super-emitter" response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties, triggering certain investigation and repair requirements. These requirements were finalized in 2023, but may be subject to legal challenge.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas such as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored "Paris Agreement," requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions ("NDCs") every five years after 2020. Following the president’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Some countries, including the United States, have additionally made commitments to reduce global methane emissions through initiatives such as the Global Methane Pledge, and have been called upon to phase out inefficient fossil fuel subsidies. However, the impacts of these actions are unclear at this time. For more information, see our risk factors titled "Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide" and "The IRA 2022 could accelerate the transition to a low carbon economy and could impose new costs on our customers’ operations."

Endangered and Threatened Species. Environmental laws such as the Endangered Species Act ("ESA") and analogous state laws may impact exploration, development and production activities in areas where we operate. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and various state analogs. The U.S. Fish and Wildlife Service ("FWS") may identify previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. For example, the dunes sagebrush lizard, which is found only in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas (including areas where our customers operate), was a candidate species for listing under the ESA by the FWS for many years. Most recently, the dunes sagebrush lizard has been proposed for listing as endangered in July 2023, FWS has also entered into voluntary conservation agreements that implement certain protective practices for the species and authorize incidental take of the species resulting from certain covered activities, including exploration and development of oil and gas fields. However, to the extent any protections are implemented for this or any other species, it could cause us or our customers to incur additional costs or become subject to operating restrictions or operating bans in the affected areas.

Regulation of Hydraulic Fracturing and Related Activities. Our hydraulic fracturing operations are a significant component of our business. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. Although several of these rulemakings have been rescinded, modified or subjected to legal challenges, new or more stringent regulations may be promulgated by the current government. For example, the Bureau of Land Management (“BLM”) recently proposed a rule that would limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if BLM finds that an operator’s methane waste minimization plan is insufficient. The current government has also called for revisions and restrictions to the leasing and permitting programs for oil and gas development on federal lands and, for a time, suspended federal oil and gas leasing activities. The Department of the Interior ("DOI") has also issued a report recommending various changes to the federal leasing program, though many such changes would require congressional action. In July 2023, the BLM proposed a rule to update the fiscal terms of federal oil and gas leases, which would increase fees, rents, royalties, and bonding requirements. The rule would also add new criteria for BLM to consider when determining whether to lease nominated land, including the presence of important habitats or wetlands, the presence of historical properties or sacred sites, and recreational use of the land. BLM anticipates a final action on the proposal in Spring 2024. As a result, we cannot predict the final scope of regulations or restrictions that may apply to oil and gas operations on federal lands. However, any regulations that restrict, ban or effectively ban such operations may adversely impact demand for our products and services. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from

OSHA Matters. The Occupational Safety and Health Act ("OSHA") and comparable state statutes regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.

Our employees are our key asset. Our primary human capital management objectives are to effectively engage, develop, retain and reward our employees. As of December 31, 2023, we employed approximately 2,070 people, and none of our employees are represented by a union. All of our employees work for or support our hydraulic fracturing, wireline and cementing operating segments. We believe that we have good relations with our employees. We believe that our employees are a key component of our ability to attract and retain customers as a result of their operational excellence in the field.

•Opportunity and Engagement. We are an equal opportunity employer and prohibit discrimination against any employee and applicant on the basis of any legally protected characteristic. We believe that in order to attract and retain talent with the skill sets and expertise that can help to maximize our operational efficiencies across all levels in the Company, it is in our best interest to create a culture that is inclusive. We conducted an employee engagement survey in 2023 related to inclusion, belonging and other engagement efforts. Some examples of this effort to recruit and develop a diverse team and create an inclusive culture include:

◦a commitment to conducting business in a manner that respects all human rights in compliance within the requirements of applicable laws;

◦a commitment within our business operations to promoting and encouraging respect for human rights and fundamental freedoms for all without distinctions of any kind, such as race, color, sex, language, religion, political or other opinions;

◦working with personnel, business partners and other parties directly linked to our operations that share our commitment to these same principles;

◦maintaining employment policies reflecting our commitments, including our code of conduct, our equal employment opportunity employer policy, and our anti-harassment and anti-discrimination policy; and

◦providing an anonymous Ethics and Compliance hotline that is promoted internally and accessible from our intranet and website to make it possible for grievances regarding health and safety to be addressed early and remediated directly, in confidence and without fear of retaliation.

•Training and Safety. We offer in-depth, role-appropriate safety training upon hiring and as part of the continuous development of our employees. The safety of our employees, our customers, and the communities in which we operate is paramount. We track and evaluate safety incidents at wellsites and offices, and if an accident does occur, we aim to take actions to mitigate similar incidents from reoccurring in the future. The Company seeks to incentivize employees to focus on conducting operations in accordance with our strict safety standards and encourages employees to immediately report any breach of safety protocol. Ten percent of our executive officers’ annual target bonuses under the 2023 annual incentive program were based upon the Company’s achievement of certain safety goals, including a target total recordable incident rate.

•Professional Development. In 2023, the Company continued its focus on leadership development, targeting leadership positions including frontline supervisors and above. In addition, we sought to make improvements to our succession planning tools and process to enable greater consistency, talent identification and development planning. We also introduced behavioral optimization tools to aid individual and team performance and talent acquisition efforts.

•Compensation, Health, Wellness and Benefits. Our employee benefit offerings are designed to meet the varied and evolving needs of a diverse workforce across the Company and we believe are consistent with those provided by our peer companies with which we compete for talent. The Company provides employees with the ability to participate in health and welfare plans, including medical, dental, life, accidental death and dismemberment and short-term and long-term disability insurance plans.

Demand for most of our services depends substantially on the level of capital expenditures in the Permian Basin by companies in the oil and natural gas industry. As a result, our operations are dependent on the levels of capital spending and activity in oil and gas exploration, development and production. Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Prolonged low oil and gas prices would generally depress the level of oil and natural gas exploration, development, production, and well completion activity and would result in a corresponding decline in the demand for the completion services that we provide. Historically, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil price per barrel was approximately $78, $94 and $68 for the years ended December 31, 2023, 2022 and 2021, respectively. In 2023, the volatility and overall decline in oil and natural gas prices caused a reduction in our customers’ spending and associated drilling and completion activities, which has had and may continue to have an adverse effect on our revenue and cash flows, if the WTI oil price remains highly volatile or declines in the future.

•the actions by the members of OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;

•the domestic and foreign supply of, and demand for, oil and natural gas;

•the level of prices, and expectations about future prices, of oil and natural gas;

•the level of global oil and natural gas E&P;

•the cost of exploring for, developing, producing and delivering oil and natural gas;

•the supply of and demand for drilling and hydraulic fracturing and wireline equipment, including the supply and demand for lower emissions hydraulic fracturing and wireline equipment;

•cost increases and supply chain constraints related to our services;

•the expected decline in rates of current production;

•the price and quantity of foreign imports;

•political and economic conditions in oil and natural gas producing countries and regions, including the United States, the Middle East, Africa, South America and Russia;

•the actions taken by the United States and other countries on climate change or to transition away from fossil fuels;

•the severity and duration of world health events and related economic repercussions;

•speculative trading in crude oil and natural gas derivative contracts;

•the level of consumer product demand;

•the discovery rates of new oil and natural gas reserves;

•contractions in the credit market;

•the strength or weakness of the U.S. dollar;

•available pipeline and other transportation capacity;

•the levels of oil and natural gas storage;

•weather conditions and other natural disasters;

•domestic and foreign tax policy;

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

•the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;

•political or civil unrest in the United States or elsewhere, including the Russia-Ukraine war and the conflict in the Israel-Gaza region and related instability in the Middle East, including from Houthi rebels in Yemen;

•technical advances affecting energy consumption;

•the proximity and capacity of oil and natural gas pipelines and other transportation facilities;

•the price and availability of alternative fuels;

•the ability of oil and natural gas producers to raise equity capital and debt financing;

•merger and divestiture activity among oil and natural gas producers; and

•overall domestic and global economic conditions.

Our operations are geographically concentrated in the Permian Basin. For the years ended December 31, 2023, 2022 and 2021, approximately 98.1%, 98.3% and 98.7%, respectively, of our revenues were attributable to our operations in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors,

The oilfield service industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent or other intellectual property protections. As competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage. The transition to lower emissions equipment is capital intensive and could require us to convert all our conventional Tier II equipment to lower emissions equipment. If we are unable to quickly transition to lower emissions equipment, the demand for our services could be adversely impacted. For example, many E&P companies, including our customers, are transitioning to a lower emissions operating environment and may require us to invest in equipment with lower emissions profiles. Further, we may face competitive pressure to develop, implement or acquire and deploy certain technology improvements at a substantial cost, such as our FORCESM electric-powered hydraulic fracturing fleets deployed in 2023, or the cost of implementing or purchasing a technology like FORCESM may be substantially higher than anticipated, and we may not be able to successfully implement the technologies we may purchase. In 2022, we recorded an impairment of $57.5 million on our DuraStim® electric-powered equipment because they did not meet our expectations. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and develop and implement new products on a timely basis or at an acceptable cost. We cannot be certain that we will be able to develop and implement new technologies or products on a timely basis or at an acceptable cost. Limits on our ability to develop, effectively use and implement new and emerging technologies could have a material adverse effect on our business, financial condition, prospects or results of operations.

The oilfield service industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures. Our total capital expenditures incurred were approximately $310.0 million, $365.3 million and $165.2 million during the years ended December 31, 2023, 2022 and 2021. We have historically financed capital expenditures primarily with funding from cash on hand, cash flow from operations, equipment and vendor financing and

borrowings under our credit facility. We may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment (including equipment with a lower emissions profile) or properly maintaining our existing equipment. Any disruptions or volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. Our borrowing base was $152.0 million as of December 31, 2023. If our customer activity levels decline in the future resulting in a decrease in our eligible accounts receivable, our borrowing base could decline. This could put us at a competitive disadvantage or interfere with our growth plans. Further, our actual capital expenditures could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of liquidity we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.

Concerns over global economic conditions, geopolitical issues (including the Russia-Ukraine war and conflicts in the Israel-Gaza region), public health crises, interest rates, inflation, the availability and cost of credit in the United States and foreign financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, could precipitate an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. The historically unpredictable nature of oil and natural gas prices, and particularly the volatility over the past two years have caused a reduction in our customers’ spending and associated drilling and completion activities, which had and may continue to have an adverse effect on our revenue and cash flows. If the economic climate in the United States or abroad deteriorates or remains uncertain, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and adversely impact our results of operations, liquidity and financial condition.

•placing us at a competitive disadvantage relative to competitors that have less debt; and

•grant liens;

•incur additional indebtedness;

•engage in a merger, consolidation or dissolution;

•enter into transactions with affiliates;

•sell or otherwise dispose of assets, businesses and operations;

•materially alter the character of our business as currently conducted; and

•make acquisitions, investments and capital expenditures.

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

Changes in future market conditions and prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses in our results of operations. These events could result in the recognition of impairment charges or losses from asset sales that negatively impact our financial results. Significant impairment charges or losses from asset sales as a result of a decline in market conditions or otherwise could have a material adverse effect on our results of operations in future periods. For example, in 2021, we recorded loss on disposal of asset $3.5 million in connection with the sale of our two turbines. In 2022, we recorded impairment charges of $57.5 million in connection with our DuraStim® electric powered hydraulic fracturing equipment. If oil and natural gas prices trade at depressed price levels, and our equipment remains idle or under-utilized, the estimated fair value of such equipment may decline, which will result in additional impairment expense in the future.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and cleanup costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the "occurrence" to our insurance company within the time frame required under our insurance policy. In addition, these policies do not provide coverage for all liabilities, and the insurance coverage may not be adequate to cover claims that may arise, or we may not be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

We operate with most of our customers under master service agreements ("MSAs"). We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer‑owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms

•delayed access to deposits or other financial assets or the uninsured loss of deposits or other financial assets;

•inability to enter into credit facilities or other working capital resources;

•potential or actual breach of contractual obligations that require the Company to maintain letters of credit or other credit support arrangements; or

•termination of cash management arrangements and/or delays in accessing or actual loss of funds subject to cash management arrangements.

The majority of our revenue is generated from our hydraulic fracturing services. Due to the large percentage of our revenue historically derived from our hydraulic fracturing services with recurring customers and the limited availability of our fracturing units, we have had some degree of customer concentration. Our top ten customers represented approximately 85.5%, 91.2% and 91.4% of our consolidated revenue for the years ended December 31, 2023, 2022 and 2021, respectively. It is likely that we will depend on a relatively small number of customers for a significant portion of our revenue in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.

Endeavor Energy Resources and XTO Energy accounted for 19.7% and 18.2%, respectively, of our revenue for the year ended December 31, 2023. If either of these customers were to significantly reduce or discontinue our services, it could have a material adverse effect on our financial condition, results of operations and cash flows. There have been many recent mergers and acquisitions in the oil and gas industry. In October 2023, Pioneer entered into a merger agreement with Exxon Mobil Corporation. Mergers and acquisitions involving our customers could negatively impact our future business with them or positively impact our business by providing us access to potential new customers.

We enter into purchase agreements with the Sand Suppliers to secure supply of sand in the normal course of our business. The agreements with the Sand Suppliers require that we purchase 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 current agreements with Sand Suppliers expire at different times prior to December 31, 2025.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, such as our Chief Executive Officer, President and Chief Operating Officer, Chief Financial Officer, Chief Accounting Officer, Chief Commercial Officer and General Counsel could disrupt our operations. We do not maintain "key person" life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recently passed laws such as the IRA 2022 advance numerous climate-related objectives. Additionally, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of certain pollutants from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. In September 2020, the government revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and the president signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, the EPA finalized a rule that established OOOOb more stringent new source and OOOOc first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Under the final rule, states will have two years to prepare and submit their plans to impose methane emissions controls on existing sources. The presumptive standards under the final rule are generally the same for both new and existing sources, including enhanced leak detection using optical gas imaging and subsequent repair equipment, and reduction of emissions by 95% through capture and control systems. The rule also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a "super-emitter" response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties, triggering certain investigation and repair requirements, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. It is likely that these requirements will be subject to legal challenge. Failure to comply with these new methane rules may result in substantial fines and penalties for non-compliance, as well as injunctive relief. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas such as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored Paris Agreement, requires member states to submit non-binding, individually-determined reduction goals known as NDCs every five years after 2020. Following the president’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at the 26th Conference of the Parties ("COP26") in Glasgow in November 2021, the United States and the European Union jointly announced the launch of the Global Methane Pledge; an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions" in the energy sector. At the 27th Conference of the Parties in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The U.S. also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At the 28th Conference of the Parties (“COP28”) in December 2023, countries reached an agreement to tackle climate change by transitioning away from fossil fuels in energy systems in a just, orderly and equitable manner. The agreement set global targets to triple the capacity of renewable energy like wind and solar power, and to double the rate of energy efficiency improvements, both by 2030, and also called on countries to accelerate low- and zero-emission technologies like carbon capture and storage. Although no firm commitment or timeline to transition away from fossil fuels was made at COP28, there can be no guarantees that countries will not seek to implement plans to transition away from fossil fuels in the future. Additionally, the agreements could result in increased pressure among financial institutions and various stakeholders to reduce or otherwise impose more stringent limitations on funding for and increase potential opposition to the production and use of fossil fuels. However, the impacts of these actions are unclear at this time.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate-change-related pledges made by certain candidates for public office. On January 27, 2021, the president issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on climate-related risk across government agencies and economic sectors. The executive order also suspended the issuance of new leases for oil and gas development on federal land; for more information, see our risk factor titled "Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays."

Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 ("Section 382") of the Internal Revenue Code of 1986, as amended (the "Code"), generally imposes an annual limitation on the amount of taxable income that may be offset by NOLs when a corporation has undergone an "ownership change" (as determined under Section 382). Generally, a change of more than 50% in the ownership of a corporation’s stock, by value, over a three‑year period constitutes an ownership change for U.S. federal income tax purposes. Any unused annual limitation may, subject to certain limitations, be carried over to later years. We may experience ownership changes, which may result in annual limitation under Section 382 determined by multiplying the value of our stock at the time of the ownership change by the applicable long‑term tax‑exempt rate as defined in Section 382, increased under certain circumstances as a result of recognizing built‑in gains in our assets existing at the time of the ownership change. The limitations arising from ownership changes may prevent utilization of our NOLs prior to their expiration. Future ownership changes or regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows if we attain profitability.

Risks Inherent to an Investment in our Common Stock

Our certificate of incorporation authorizes our board of directors (the "Board") to issue preferred stock without shareholder approval. If our Board elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our shareholders, including:

•limitations on the removal of directors;

•limitations on the ability of our shareholders to call special meetings;

•advance notice provisions for shareholder proposals and nominations for elections to the Board to be acted upon at meetings of shareholders;

•providing that the Board is expressly authorized to adopt, or to alter or repeal our bylaws; and

•establishing advance notice and certain information requirements for nominations for election to our Board or for proposing matters that can be acted upon by shareholders at shareholder meetings.

Disclosure concerning legal proceedings is incorporated by reference to "Note 18. Commitments and Contingencies— Contingent Liabilities" of our Consolidated Financial Statements contained in this Annual Report.

(1)On May 17, 2023, the Board authorized and the Company announced a share purchase program that allows the Company to repurchase up to $100 million of the Company's common stock beginning immediately and continuing through and including May 31, 2024. 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.

(2)The average price paid per share includes commissions.

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.

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.

We are a leading integrated oilfield service company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline and other complementary oilfield completion 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 78.5% of our total revenues and operations. Our total available hydraulic horsepower ("HHP") at December 31, 2023 was 1,461,500 HHP, which was comprised of 452,500 HHP of our Tier IV Dynamic Gas Blending (“DGB”) dual-fuel equipment, 144,000 HHP of FORCESM electric-powered equipment and 865,000 HHP of conventional Tier II equipment. Our hydraulic fracturing fleets range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsite. Our equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region’s increasingly high-intensity well completions (including simultaneous hydraulic fracturing ("Simul-Frac"), which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in 2021 and 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and to purchase new Tier IV DGB dual-fuel equipment. As such, we entered into conversion and purchase agreements with our equipment manufacturers for a total of 452,500 HHP of Tier IV DGB dual-fuel equipment and as of December 31, 2023, we have received all of the converted and new Tier IV DGB dual-fuel equipment. In 2022, we entered into three-year electric fleet leases for a total of four FORCESM electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet. As of December 31, 2023, we have received 144,000 HHP of FORCESM electric-powered equipment. We currently expect to receive the remaining equipment associated with the second and third fleets and all equipment associated with the fourth fleet in the first half of 2024.

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. Par Five’s business complements our existing cementing business and enables us to serve both the Midland and Delaware Basins of the Permian Basin.

We have historically conducted our business through four operating segments: hydraulic fracturing, wireline, cementing and coiled tubing. Prior to the fourth quarter of fiscal year 2023, our operating segments met the aggregation criteria and were aggregated into the “Completion Services” reportable segment and our coiled tubing operations (which were divested in September 2022) were shown in the “All Other” category. Effective as of the fourth quarter of fiscal year 2023, we revised our segment reporting as we determined that our three operating segments no longer met the criteria to be aggregated. Our Hydraulic Fracturing and Wireline operating segments meet the criteria of a reportable segment. Our cementing and our divested coiled tubing segments are not material, are not separately reportable, and are included within the “All Other” category. Prior period segment information has been revised to conform to our current presentation. For additional financial information on our reportable segments presentation, please see reportable segment information in Part II - Item 8, "Financial Statements and Supplementary Data."

On 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, and concurrently entered into a pressure pumping services agreement (the "Pioneer Services Agreement") with Pioneer.

Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including upstream and oilfield service companies. As a result, we are working with our customers and equipment manufacturers to transition our equipment to a lower emissions profile. Currently, a number of lower emission solutions for pumping equipment, including Tier IV DGB dual-fuel, FORCESM electric, direct drive gas turbine and other technologies have been developed, and we expect additional lower emission solutions will be developed in the future. We are continually evaluating these technologies and other investment and acquisition opportunities that would support our existing and new customer relationships. The transition to lower emissions equipment is quickly evolving and will be capital intensive. Over time, we may be required to convert substantially all of our conventional Tier II equipment to lower emissions equipment. We have transitioned our hydraulic fracturing available equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022 and 60% in 2023, and expect to increase to approximately 65% by the end of the first half of 2024. To the extent any of our customers have certain expectations or requirements with respect to emissions reductions from their contractors, if we are unable to continue quickly transitioning to lower emissions equipment, the demand for our services could be adversely impacted.

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

•improved pricing and increased operational efficiency at wellsites;

•our average effectively utilized hydraulic fracturing fleet count was approximately 15 active fleets, consistent with 15 active fleets in 2022;

•successfully integrated our wireline business with our existing hydraulic fracturing and cementing businesses;

•deployed two FORCESM electric-powered hydraulic fracturing fleets with a total capacity of 120,000 HHP, and transitioned 452,500 HHP of our equipment portfolio to lower emissions, Tier IV DGB dual-fuel equipment. By adding two additional electric fleets by the end of the first half of 2024, our available equipment portfolio is expected to be comprised of approximately 65% lower emissions (FORCESM electric and Tier IV DGB dual-fuel), and 35% conventional diesel equipment;

•published our inaugural sustainability report, which describes our commitment to building a sustainable business that supports the safe, reliable production of the energy the world needs by offering competitive, value-driving services to customers, while benefitting our shareholders, communities, and other stakeholders; and

•on December 1, 2023, we consummated the purchase of the assets and operations of Par Five, which provides cementing services in the Delaware Basin.

•revenue increased $350.7 million, or 27.4%, to $1,630.4 million, as compared to $1,279.7 million for the year ended December 31, 2022;

•cost of services (exclusive of depreciation and amortization) increased $249.0 million or 28.2% to $1,131.8 million, as compared to $882.8 million for the year ended December 31, 2022; cost of services as a percentage of revenue increased to 69.4% in 2023 compared to 69.0% for the year ended December 31, 2022;

•general and administrative expenses, inclusive of stock-based compensation, increased $2.6 million, or 2.3% to $114.4 million, as compared to $111.8 million for the year ended December 31, 2022;

•no impairment expense was recorded during the year December 31, 2023, compared to $57.5 million impairment expense recorded during the year ended December 31, 2022 related to our DuraStim® electric-powered hydraulic fracturing equipment;

•net income was $85.6 million, compared to $2.0 million for the year ended December 31, 2022. Diluted net income per common share was $0.76, compared to $0.02 for the year ended December 31, 2022. Adjusted EBITDA of approximately $404.0 million increased 27.6%, compared to $316.6 million for the year ended December 31, 2022 (see reconciliation of Adjusted EBITDA to net income in the subsequent section "How We Evaluate Our Operations");

•our total liquidity was $134.4 million, consisting of cash, cash equivalents and restricted cash of $33.4 million and remaining availability of $101.0 million under our ABL Credit Facility; $45.0 million of borrowings as of December 31, 2023 under our ABL Credit Facility; and

•the Company repurchased and retired 5.8 million shares of common stock for an aggregate of $51.7 million, an average price per share of $8.93 including commissions, under the repurchase program. As of December 31, 2023, $48.3 million remained authorized for future repurchases of common stock under the repurchase program.

•In connection with the review of our power ends estimated useful life, effective January 1, 2023, we are writing off the remaining book value of power ends that prematurely fail as accelerated depreciation. These write-off amounts were $12.5 million, $11.8 million, $8.4 million and $6.0 million for the three months ended March, 31, 2023, June 30, 2023, September 30, 2023 and December 31, 2023, respectively. However, to conform to prior year presentation, we have presented these write-off amounts within loss on disposal of assets for the year ended December 31, 2023. In 2022 and 2021, we wrote off the remaining book value of prematurely failed and disposed of power ends to loss on disposal of assets.

Completion services includes our hydraulic fracturing, wireline and cementing operations. We primarily provide these services to E&P companies in the Permian Basin. During the year ended December 31, 2023, our hydraulic fracturing, wireline and cementing operations accounted for 78.5%, 14.1% and 7.4% of our total revenue, respectively. Our 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. We plan to continually reinvest in our equipment to ensure optimal performance and reliability.

Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil price per barrel was approximately $78, $94 and $68 for the years ended December 31, 2023, 2022 and 2021, respectively. In January 2024, the WTI oil price was approximately $74 per barrel. If the WTI oil price declines in the future or remains highly volatile, demand for our services may be negatively impacted, which could result in a significant decrease in our future profitability and cash flows. We monitor oil and natural gas prices and the Permian Basin rig count to enable us to more effectively plan our business and forecast the demand for our services.

Direct Labor Costs. Payroll and benefit expenses related to our crews and other employees that are directly or indirectly attributable to the effective delivery of services are included in our operating costs. Direct labor costs amounted to 28.7% and 27.7% of total costs of service for the years ended December 31, 2023 and 2022, respectively. The increase in our direct labor costs percentage is driven by wage adjustments and higher headcount resulting from business acquisitions.

Expendables. Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our completion services and other operations. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services. Expendable product costs comprised approximately 32.9% and 33.6% of total costs of service for the years ended December 31, 2023 and 2022, respectively. The percentage decrease in our expendables in 2023 was primarily attributable to certain customers electing to directly source sand and the associated logistics.

Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental 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 38.4% and 38.7% of total costs of service for the years ended December 31, 2023 and 2022, respectively.

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

(1)Includes settlement expenses resulting from routine audits.

(2)Represents expense in connection with the impairment of our DuraStim® electric-powered hydraulic fracturing equipment.

(3)Includes $2.7 million of non-cash income from fixed asset inventory received as part of a settlement of warranty claims with an equipment manufacturer.

(4)Includes legal settlement to a vendor and other legal matters, net of reimbursement from insurance carriers.

In 2023, we conducted our business through three operating segments: hydraulic fracturing, wireline, and cementing. Our cementing operating segment and coiled tubing operations are shown in the “All Other” category for segment reporting purposes. We disposed of our coiled tubing assets and shut down our coiled tubing operations effective September 1, 2022.

(4)    For definitions of the non‑GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin to our most directly comparable financial measures calculated in accordance with GAAP, please read "How We Evaluate Our Operations." Included in our Adjusted EBITDA is reservation and idle fees of $0 and $27.0 million for the years ended December 31, 2023 and 2022, respectively.

Revenue.  Revenue increased 27.4%, or $350.7 million, to $1,630.4 million for the year ended December 31, 2023, as compared to $1,279.7 million for the year ended December 31, 2022. Revenue by reportable segment was as follows:

Hydraulic Fracturing. Our hydraulic fracturing segment revenues increased 12.0%, or $137.3 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to the increase in our existing and new customers' activity levels, resulting in higher demand for completion services, and improved pricing. Our effectively utilized hydraulic fracturing fleet count was flat at 15 active fleets for the year ended December 31, 2023, as in the year ended December 31, 2022. The effectively utilized fleet count is determined by dividing the total number of days our fleets were actively working at wellsites during the month by 25 days (predetermined number of expected active work days in the month). Our revenue for the years ended December 31, 2023 and December 31, 2022 included reservation fees charged to a customer of approximately $0 and $27.0 million, respectively.

Wireline. Our wireline segment revenue increased 636.2%, or $198.4 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to a full year of activity for the year ended December 31, 2023 compared to only 61 days of activity during year ended December 31, 2022 since the wireline business was acquired on November 1, 2022.

All Other. Revenue from the All Other category comprising of our cementing and our disposed of coiled tubing operations increased 14.2%, or $15.0 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to the increase in our existing and new customers' activity levels, resulting in higher demand for completion services, and improved pricing, partially offset by the discontinuation of our coiled tubing operations effective September 1, 2022.

Cost of Services.  Cost of services increased 28.2%, or $249.0 million, to $1,131.8 million for the year ended December 31, 2023, from $882.8 million during the year ended December 31, 2022. Cost of services by reportable segment was as follows:

Hydraulic Fracturing. Cost of services for our hydraulic fracturing segment increased $110.1 million during the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to increased activity levels resulting from the increased demand for our services as compared to 2022, and the impact of general cost inflation. As a percentage of hydraulic fracturing revenues (including reservation fees), hydraulic fracturing cost of services increased to 69.2% for the year ended December 31, 2023, as compared to 67.9% for the year ended December 31, 2022. Excluding reservation fees revenue of $0 and $27.0 million for the years ended December 31, 2023 and 2022, respectively, our hydraulic fracturing cost of services as a percentage of hydraulic fracturing revenues for the years ended December 31, 2023 and 2022 was approximately 69.2% and 69.5%, respectively. The decrease was a result of increased operational efficiencies and improved customer pricing, partially offset by costs of $38.0 million associated with the replacement of fluid ends during the year ended December 31, 2023. Fluid ends were capitalized and depreciated in 2022. Effective January 1, 2023, the Company commenced expensing fluid ends as part of cost of services rather than capitalizing fluid ends as part of property and equipment as a result of the change in estimated useful life.

Wireline. Our wireline segment cost of services increased 634.9%, or $134.2 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to a full year of activity for the the year ended December 31, 2023 compared to only 61 days of activity during year ended December 31, 2022 since the wireline business was acquired on November 1, 2022.

All Other. Cost of services for the All Other category comprising of our cementing and our disposed of coiled tubing operations increased 5.4%, or $4.6 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily attributable to increased activity levels resulting from the increased demand for our services as compared to 2022, and the impact of general cost inflation, partially offset by the discontinuation of our coiled tubing operations effective September 1, 2022.

General and Administrative Expenses.  General and administrative expenses increased 2.3%, or $2.6 million, to $114.4 million for the year ended December 31, 2023, as compared to $111.8 million for the year ended December 31, 2022. The net increase was primarily attributable to (i) a $6.3 million increase in payroll and related expenses, (ii) a $5.1 million increase in utilities, advertising and other office expenses, (iii) a $2.1 million increase in travel expenses, and (iv) a $0.4 million net increase in

Excluding nonrecurring and non-cash items (i.e., stock-based compensation of $14.5 million, legal settlements (net of insurance reimbursements) of $0.7 million, transaction expenses of $2.3 million, and retention bonuses and severance expenses of $2.3 million), general and administrative expenses were $94.6 million for the year ended December 31, 2023, as compared to $80.3 million for the year ended December 31, 2022.

Depreciation and Amortization.  Depreciation and amortization increased 41.2%, or $52.8 million, to $180.9 million for the year ended December 31, 2023, as compared to $128.1 million for the year ended December 31, 2022. The increase was primarily attributable to the increase in our fixed asset base as of December 31, 2023.

Impairment Expense.  There was no impairment expense during the year ended December 31, 2023. During the year ended December 31, 2022, we recorded $57.5 million in connection with the impairment of our DuraStim® electric powered hydraulic fracturing equipment, which is included in our Hydraulic Fracturing reportable segment.

Loss on Disposal of Assets.  Loss on the disposal of assets decreased 28.5%, or $29.1 million, to $73.0 million for the year ended December 31, 2023, as compared to $102.1 million for the year ended December 31, 2022. The decrease was primarily attributable to a loss of approximately $13.8 million from the disposal of our coiled tubing assets on September 1, 2022 and the Company expensing costs associated with replacement of fluid ends as part of cost of services resulting from the change in estimated useful life effective January 1, 2023, partially offset by losses incurred from the decommissioning/conversion of certain hydraulic fracturing equipment and the write-off of certain hydraulic fracturing equipment as a result of an accidental fire at a wellsite in March 2023.

Interest Expense.  Interest expense increased to $5.3 million for the year ended December 31, 2023, as compared to $1.6 million for the year ended December 31, 2022. The increase was primarily attributable to higher average outstanding borrowings under our ABL Credit Facility during the year ended December 31, 2023 and the addition of a finance lease for certain power generation equipment in August 2023.

Other Expense (Income).  Other expense was approximately $9.5 million for the year ended December 31, 2023, as compared to other income of $11.6 million for the year ended December 31, 2022. Other expense during the year ended December 31, 2023 is primarily comprised of settlement expenses resulting from routine audits and one-time health insurance costs totaling approximately $7.4 million, and a $2.5 million unrealized loss on short-term investment. Other income during the year ended December 31, 2022 is comprised of a $10.7 million net tax refund of sales, excise and use taxes and $2.7 million of non-cash income from equipment parts inventory received from an equipment manufacturer as settlement of our warranty claims, partially offset by a $1.6 million unrealized loss on short-term investment.

Income Taxes.  Total income tax expense was $29.9 million resulting in an effective tax rate of 25.9% for the year ended December 31, 2023, as compared to $5.4 million or an effective tax rate of 72.5% for the year ended December 31, 2022. The change in income tax expense recorded during the year ended December 31, 2023, compared to the year ended December 31, 2022, is primarily attributable to the difference in the impact of nondeductible expenses on the pre-tax income for 2023, as compared to 2022.

Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility (as defined below). Our cash is primarily used to fund our operations, support growth opportunities, fund share repurchases under our share repurchase program and satisfy future debt payments. Our restricted cash, which was received from a customer will be used solely for the construction or operation of FORCESM electric-powered hydraulic fracturing equipment. Our Borrowing Base (as defined below), as redetermined monthly, is tied to the sum of 85% to 90% of monthly eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the Borrowing Base), in each case, depending on the credit ratings of our accounts receivable counterparties, less customary reserves. Changes to our operational activity levels and our customers’ credit ratings have an impact on our total eligible accounts receivable, which could result in significant changes to our Borrowing Base and, therefore, our availability under our ABL Credit Facility.

We received advance payments from a customer for our services, and the amount outstanding in connection with the advance payments was $19.2 million and $10.0 million as of December 31, 2023 and 2022, respectively. These amounts included restricted cash of $0 and $10.0 million as of December 31, 2023 and 2022, respectively.

As of December 31, 2023, our borrowings under our ABL Credit Facility were $45.0 million and our total liquidity was $134.4 million, consisting of cash and cash equivalents of $33.4 million and $101.0 million of availability under our ABL Credit Facility.

On May 17, 2023, the Board authorized and the Company announced a share repurchase program that allows the Company to repurchase up to $100 million of the Company's common stock beginning immediately and continuing through and including May 31, 2024. 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 repurchase program, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund the repurchases using cash on hand and expected free cash flow to be generated through May 2024. During the year ended December 31, 2023, the Company repurchased and retired 5.8 million shares of common stock for an aggregate of $51.7 million, an average price per share of $8.93 including commissions, under the repurchase program. As of December 31, 2023, $48.3 million remained authorized for future repurchases of common stock under the repurchase program.

As part of our real estate consolidation strategy, we sold our corporate office building and the associated real property in August 2023 for cash proceeds of $4.7 million after commission and closing costs and recognized a gain on disposal of assets of $0.1 million during the year ended December 31, 2023. We have subsequently relocated our corporate office to a leased office space. See "Note 17 - Leases" for further information.

The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2023 and 2022, respectively.

Net cash provided by operating activities was $374.7 million for the year ended December 31, 2023, as compared to $300.4 million for the year ended December 31, 2022. The net increase of $74.3 million was primarily due to the improvement in our net income, resulting from the increase in our existing and new customers' activity levels, resulting in higher demand for completion services, increased operational efficiencies and the addition of wireline operations. The increase in cash provided by operating activities was also impacted by timing of our receivable collections from our customers and payments to our vendors, partially offset by increases in inventories and prepaid expenses.

_________________

Net cash used in financing activities was $46.1 million for the year ended December 31, 2023, compared to net cash provided by of $26.3 million for the year ended December 31, 2022. The net increase was primarily driven by share repurchases of $51.7 million, repayments of borrowings of $15.0 million and payments of finance lease obligation of $4.7 million.

Effective June 2, 2023, 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 and as may be amended further, "ABL Credit Facility"). The amendment increased the borrowing capacity under the ABL Credit Facility to $225.0 million (subject to the Borrowing Base limit), and extended the maturity date to June 2, 2028. The ABL Credit Facility has a borrowing base of the sum of 85% to 90% of monthly eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the Borrowing Base) less customary reserves (the "Borrowing Base"), in each case, depending on the credit ratings of our accounts receivable counterparties, as redetermined monthly. The Borrowing Base as of December 31, 2023, was approximately $152.0 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.

The loan origination costs relating to the ABL Credit Facility are classified as an asset in our balance sheet. As of December 31, 2023 and 2022, we had outstanding borrowings under our ABL Credit Facility of $45.0 million and $30.0 million, respectively.

Capital expenditures incurred were $310.0 million during the year ended December 31, 2023, as compared to $365.3 million during the year ended December 31, 2022. The significant portion of our total capital expenditures incurred during the year ended December 31, 2023 were maintenance capital expenditures and conversion of our hydraulic fracturing equipment to lower emissions equipment.

Our future material use of cash will be to fund our capital expenditures. Capital expenditures for 2024 are projected to be primarily related to capital expenditures to extend the useful life of our existing completion services assets, costs to convert some existing equipment to lower emissions equipment, strategic purchases and other ancillary equipment purchases, subject to market conditions and customer demand. Our future capital expenditures depend on our projected operational activity, emission requirements and planned conversions to lower emissions equipment, among other factors, which could vary significantly throughout the year. Based on our current plan and projected activity levels for 2024, we expect our capital expenditures to range between $200 million to $250 million. We could incur significant additional capital expenditures if our projected activity levels increase during the course of the year, inflation and supply chain tightness continues to adversely impact our operations or we invest in new or different lower emissions equipment. The Company will continue to evaluate the emissions profile of its equipment over the coming years and may, depending on market conditions, convert or retire additional conventional Tier II equipment in favor of lower emissions equipment. The Company’s decisions regarding the retirement or conversion of equipment or the addition of lower emissions equipment will be subject to a number of factors, including (among other factors)

the availability of equipment, including parts and major components, supply chain disruptions, prevailing and expected commodity prices, customer demand and requirements and the Company’s evaluation of projected returns on conversion or other capital expenditures. Depending on the impacts of these factors, the Company may decide to retain conventional equipment for a longer period of time or accelerate the retirement, replacement or conversion of that equipment.

(1)Exclusive of future commitment fees, amortization of deferred financing costs, interest expense or other fees on our ABL Credit Facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments of future interest rates to be changed. However, assuming a weighted average interest rate of 6.69%, and that our ABL Credit Facility debt balance remains the same, our estimated annual interest payment will be $3.0 million.

(2)Operating leases exclude short-term leases and other commitments (see Note 17. Leases and Note 18. Commitments and Contingencies in the financial statements for additional disclosures).

(3)Includes our leases for FORCESM electric-powered hydraulic fracturing fleets (240,000 HHP). We expect to receive the remaining equipment under these leases in the first half of 2024.

(4)Finance lease for certain power generation equipment (70 MW) to support electric-powered hydraulic fracturing equipment.

(5)Relates to a take-or-pay sand commitment with one of our sand vendors.

(6)Represents the unpaid portion of the purchase consideration on our acquisition of Par Five assets to be used to cover the amount by which the estimated purchase price exceeds the final purchase price, if any.

We enter into other purchase agreements with Sand Suppliers to secure supply of sand in the normal course of our business. The agreements with the Sand Suppliers require that we purchase 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 current agreements with Sand Suppliers expire at different times prior to December 31, 2025. Our agreed upon sand requirements or minimum volumes are based on certain future events such as our customer demand, which cannot be reasonably estimated. If the activity level of our customers declines and the future demand for our services is materially and adversely affected, we may be required to pay for more sand from one of our Sand Suppliers than we need in the performance of our services, regardless of whether we take physical delivery of such sand. In such an event, we may be required to pay shortfall fees or other penalties under the purchase agreement, which could have a material adverse effect on our business, financial condition, or results of operations.

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.

We primarily retire certain components of equipment such as fluid ends and power ends, rather than the entire pieces of equipment. The associated loss is recorded in our statement of operations as part of net loss on disposal of assets, which was $73.0 million, $102.1 million and $64.6 million for the years ended December 31, 2023, 2022 and 2021, respectively.

In accordance with the Financial Accounting Standards Board Accounting Standards Codification ("ASC") 360 regarding Accounting for the Impairment or Disposal of Long‑Lived Assets, we review the long‑lived assets including intangible assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable to the assets is less than the carrying amount of such assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset. Our cash flow forecasts require us to make certain judgments regarding long‑term forecasts of future revenue and costs and cash flows related to the assets subject to review. The significant assumption in our cash flow forecasts is our estimated equipment utilization and profitability. The significant assumption is uncertain in that it is driven by future demand for our services and utilization, which could be impacted by crude oil market prices, future market conditions and technological advancements. Our fair value estimates for certain long‑lived assets require us to use significant other observable inputs, including assumptions related to market based on recent auction sales or selling prices of comparable equipment. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future.

If the crude oil market declines or the demand for our services does not recover, and if our equipment remains idle or underutilized, the estimated fair value of such equipment may decline, which could result in future impairment charges. Though the impacts of variations in any of these factors can have compounding or offsetting impacts, a 10% decline in the estimated future cash flows of our existing asset groups will not indicate an impairment.

In 2022, we recorded impairment expense of $57.5 million on our DuraStim® electric-powered hydraulic fracturing equipment within the hydraulic fracturing operating segment.

In connection with the Silvertip Acquisition, we added $23.6 million of goodwill during the year ended December 31, 2022. There were no additions to goodwill during the year ended December 31, 2023. The wireline operating segment is the only segment with goodwill at December 31, 2023 and 2022. There were no goodwill impairment losses during the years ended December 31, 2023 and 2022. We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles—Goodwill and Other, on December 31, 2023, at which time, we determined that the fair value of our wireline reporting unit was substantially in excess of its carrying value. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted equipment utilization, pricing and cost assumptions. Our discounted cash flow analysis includes significant assumptions regarding discount rates, utilization, expected profitability margin, forecasted maintenance capital expenditures, and the timing of expected cash flow. As such, our goodwill analysis incorporates inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecast. As of December 31, 2023 and 2022, our goodwill carrying value was $23.6 million and $23.6 million, respectively.

Intangible assets consist of customer relationships and trademark/trade name. In connection with the Silvertip Acquisition, we added intangible assets consisting of $46.5 million of customer relationships and $10.8 million of trademark/trade name during the year ended December 31, 2022. Intangible assets are amortized on a straight‑line basis with an estimated useful life of ten years. Our estimated useful life could be sensitive to changes in market conditions and management’s judgment, and are likely to change in the future if certain events occur. Presently, there are no events or circumstances that will cause us to believe that our estimated useful life for our intangible assets are likely to change.

We may be subject to interest rate risk on variable rate borrowings under our ABL Credit Facility. We do not currently engage in interest rate derivatives to hedge our interest rate risk. The impact of a 1% increase in interest rates on our variable rate debt would have resulted in an increase in interest expense and corresponding decrease/(increase) in pre‑tax income/(loss) of approximately $0.5 million, $0.1 million and $0, for the years ended December 31, 2023, 2022 and 2021, respectively.

We have audited the accompanying consolidated balance sheet of ProPetro Holding Corp. and Subsidiaries (the Company) as of December 31, 2023, the related consolidated statements of operations, shareholders’ equity and cash flows, for the year then ended, and the related notes (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013, and our report dated March 13, 2024, expressed an opinion that the Company had not maintained effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.

Our audit procedures related to the fair value of property and equipment acquired as part of the Acquisition included the following, among others:

•We obtained an understanding of the relevant controls related to the recording of assets acquired and liabilities assumed in a business combination and tested such controls for design and operating effectiveness.

•With the assistance of our internal valuation specialists, we evaluated the reasonableness of the valuation methodology and significant assumptions including estimates of trend factor calculation, replacement cost, normal useful life, and economic obsolescence by (1) evaluating the source information and assumptions used by management, (2) testing the mathematical accuracy of the calculation, and (3) comparing our estimates to those used by management.

We have audited ProPetro Holding Corp and Subsidiaries (the Company’s) internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. In our opinion, because of the effect of the material weakness described below on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements of the Company as of and for the year ended December 31, 2023 and our report dated March 13, 2024 expressed an unqualified opinion on those consolidated financial statements.

This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2023 consolidated financial statements, and this report does not affect our report dated March 13, 2024, on those consolidated financial statements.

(In thousands, except share data)

			2023						2022
ASSETS
CURRENT ASSETS:
Cash, cash equivalents and restricted cash			$	33,354					$	88,862
Accounts receivable - net of allowance for credit losses of $236 and $419, respectively			237,012						215,925
Inventories			17,705						5,034
Prepaid expenses			14,640						8,643
Short-term investment, net			7,745						10,283
Other current assets			353						38
Total current assets			310,809						328,785
PROPERTY AND EQUIPMENT - Net of accumulated depreciation			967,116						922,735
OPERATING LEASE RIGHT-OF-USE ASSETS			78,583						3,147
FINANCE LEASE RIGHT-OF-USE ASSETS			47,449						—
OTHER NONCURRENT ASSETS:
Goodwill			23,624						23,624
Intangible assets - net of amortization			50,615						56,345
Other noncurrent assets			2,116						1,150
Total other noncurrent assets			76,355						81,119
TOTAL ASSETS			$	1,480,312					$	1,335,786
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable			$	161,441					$	234,299
Accrued and other current liabilities			75,616						49,027
Operating lease liabilities			17,029						854
Finance lease liabilities			17,063						—
Total current liabilities			271,149						284,180
DEFERRED INCOME TAXES			93,105						65,265
LONG-TERM DEBT			45,000						30,000
NONCURRENT OPERATING LEASE LIABILITIES			38,600						2,308
NONCURRENT FINANCE LEASE LIABILITIES			30,886						—
OTHER LONG-TERM LIABILITIES			3,180						—
Total liabilities			481,920						381,753
COMMITMENTS AND CONTINGENCIES (Note 18)
SHAREHOLDERS’ EQUITY:
Preferred stock, $0.001 par value, 30,000,000 shares authorized, none issued, respectively			—						—
Common stock, $0.001 par value, 200,000,000 shares authorized, 109,483,281 and 114,515,008 shares issued and outstanding, respectively			109						114
Additional paid-in capital			929,249						970,519
Retained earnings (accumulated deficit)			69,034						(16,600)
Total shareholders’ equity			998,392						954,033
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY			$	1,480,312					$	1,335,786