FORM 10-K

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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 aggregate market value of the Company’s Common Stock held by nonaffiliates on June 30, 2022, determined using the per share closing price on the New York Stock Exchange Composite tape of $10.00 on that date, was approximately $726.8 million.

This Annual Report on Form 10-K (the "Annual Report") contains forward‑looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words "may," "could," "plan," "project," "budget," "predict," "pursue," "target," "seek," "objective," "believe," "expect," "anticipate," "intend," "estimate," and other expressions that are predictions of, or indicate, future events and trends and that do not relate to historical matters identify forward‑looking statements. Our forward‑looking statements include, among other matters, statements about our business strategy, industry, future profitability, including statements about our expected growth from the Silvertip Acquisition, expected capital expenditures and the impact of such expenditures on our performance and capital programs.

•operational challenges from the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;

•the severity and duration of any world events and armed conflict, like the Russian-Ukraine war 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 Biden Administration, 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;

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

•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;

•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 services equipment and similar advancements;

•changes in the availability and cost of capital;

•our ability to successfully implement our business plan, including integrating the recently acquired wireline business from the Silvertip Acquisition and execution of other 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 the Company 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 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 DGB and electric hydraulic fracturing equipment, and other lower-emissions equipment we may acquire or that may be sought by our customers;

•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control, 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 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") could accelerate the transition to a low carbon economy and could impose new costs on our customers’ operations.

•The COVID-19 outbreak has negatively impacted, and may continue to negatively impact crude oil prices and demand for our products and services.

•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 Asset Backed Loan (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 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 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 may be limited.

Risks Inherent to an Investment in our Common Stock

•We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act ("Section 404"). If we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.

•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 services 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.

Effective September 1, 2022, we disposed of our coiled tubing assets to STEP Energy Services (USA) 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, which have an estimated fair value of $11.8 million, as consideration. Upon the sale of our coiled tubing assets, we recorded a loss on sale of $13.8 million.

The Russia-Ukraine war, and the adverse impacts of the COVID-19 pandemic in recent years, including inflation, have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing. In 2022, West Texas Intermediate ("WTI") average crude oil price was approximately $94 per barrel, which is the highest average price in the last nine years. We believe that the recent surge in global crude oil prices is partly due to the lack of reinvestment in the oil and gas industry in the last two years, and increased demand for oil and gas products, coupled with the adverse impact of the Russia-Ukraine war, which has led to various sanctions on Russian crude oil supply and businesses. With the significant increase in global crude oil prices, including WTI crude oil prices, there has been an increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of December 2022, according to Baker Hughes. Following the increase in rig count and WTI crude oil price, the oilfield service industry has experienced increased demand for its oil well completion services, and improved pricing. As a result of the growing demand for oil well completion services and significant cost inflation across the industry, we negotiated pricing increases with certain of our customers for our oil well completion services, depending on job design. Although we are currently operating in an improved pricing environment compared to 2020 and 2021, the rapid increase in cost inflation and supply chain tightness could adversely impact our future profitability. The U.S. inflation rate has been steadily increasing since 2021. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including labor costs and equipment. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to timely pass-through the cost increases to our customers, would negatively impact our business, financial condition and results of operations. See Part II, Item 1A. "Risk Factors—Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."

Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including the upstream and oilfield services 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 Dynamic Gas Blending ("DGB"), 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 active hydraulic fracturing equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022, and expect to increase to approximately 65% in 2023.

The Permian Basin rig count increase, demand for oil and gas products, WTI crude oil price increase and costs inflation could be indicative of an energy market recovery. If the rig count and market conditions continue to improve, including improved customers' pricing and labor availability, and we are able to continue to meet our customers' lower emissions equipment demands, we believe our operational and financial results will also continue to improve. However, if 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.

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, 2022 was 1,315,000 HHP, which was comprised of 252,500 HHP of our Tier IV DGB equipment and 1,062,500 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. During the year ended December 31, 2022, we recorded an impairment with respect to our DuraStim® hydraulic fracturing pumps (108,000 HHP) that did not meet the manufacturer’s specifications or our expectations and have remained idled. With the industry transition to lower emissions equipment and simultaneous hydraulic fracturing ("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 September 2021, August 2022 and December 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and purchase of new Tier IV DGB equipment. As such, we entered into conversion and purchase agreements with our equipment manufacturers for a total of 362,500 HHP of Tier IV DGB equipment and as of December 31, 2022, we have received 192,500 HHP of the converted and new Tier IV DGB equipment and expect to receive the remaining 170,000 HHP by the second quarter of 2023. In August 2022 and December 2022, we entered into leases for four electric fleets of 60,000 HHP per fleet. We expect to take delivery of the electric fleets at different times during the second half of 2023. We have entered into a contract with a customer for the use of one of our electric hydraulic fracturing fleets to provide committed services for a period of three years after we take delivery of the fleet.

We own and operate a fleet of mobile wireline units and other auxiliary equipment to perform well completion services. We also refer to our wireline units, pressure control equipment, other equipment and vehicles necessary to perform a job as a "spread" and the personnel assigned to the spread as a "crew." On average, one wireline spread consists of a wireline tractor truck with a large cab functioning as mobile office where the engineer controls the wireline spooled drum along with associated pressure control iron and equipment, trailers and vehicles. We currently have 23 wireline units.

Our customers consist primarily of oil and natural gas producers in North America. Our top five customers accounted for approximately 84.0%, 85.7% and 86.5% of our revenue, for the years ended December 31, 2022, 2021 and 2020, respectively. For the year ended December 31, 2022, Pioneer Natural Resources USA Inc. ("Pioneer"), Endeavor Energy Resources and XTO Energy accounted for 33.1%, 28.3% and 15.0%, respectively, of total revenue. No other customer accounted for more than 10% of our total revenue for the year ended December 31, 2022.

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 (the "Pioneer Pressure Pumping Acquisition"). The A&R Pressure Pumping Services Agreement, which was effective from January 1, 2022 to December 31, 2022, reduced the number of contracted fleets to six fleets from eight fleets, modified the pressure pumping scope of work and pricing mechanism for contracted fleets, and replaced the idle fees arrangement with equipment reservation fees (the "Reservation fees"). As part of the Reservation fees arrangement, the Company was entitled to receive compensation for all eligible contracted fleets that were made available to Pioneer at the beginning of every quarter in 2022 through the term of the A&R Pressure Pumping Services Agreement. 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.

On October 31, 2022, we entered into two pressure pumping services agreements with Pioneer, pursuant to which we will provide hydraulic fracturing services with two committed fleets, subject to certain termination and release rights. The Fleet One Agreement was effective as of January 1, 2023 and will terminate on August 31, 2023. The Fleet Two Agreement was effective as of January 1, 2023 and was originally planned to terminate on the one year anniversary of the date on which the fleet dedicated thereunder converted from a Tier II diesel Simul-Frac fleet to a Tier IV dual fuel zipper fleet, which was expected to occur in May 2023. In February 2023, Pioneer provided the Company notice (i) stating that Pioneer intended to release Fleet Two effective upon the completion of operations on the pad where the performance of Services (as defined in the Fleet Two Agreement) is in progress on May 12, 2023 (the “Release Date”) and (ii) requesting that the Company agree to the termination of the Fleet Two Agreement as of the Release Date. The Company agreed with such request, and, as a result, the Fleet Two Agreement will be terminated as of the Release Date.

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 election of President Biden and 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

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 our operations, we use materials that, if released, would be subject to CERCLA and comparable state laws. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such hazardous substances have been released.

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. In September 2020, the Trump Administration 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 President Biden 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, the EPA has proposed more recent 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. Certain of these requirements are currently subject to public comment, and the rule is expected to be finalized in 2023; however, it is likely that these requirements will 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 President Biden’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

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, President Biden 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 suspends the issuance of new leases for oil and gas development on federal land; for more information, see our regulatory disclosure titled "Regulation of Hydraulic Fracturing and Related Activities." Other actions that the Biden Administration may take include the imposition of more restrictive requirements for the development of pipeline infrastructure or liquefied natural gas export facilities or more restrictive GHG emissions limitations for oil and gas facilities. Litigation risks are also increasing as a number of parties have sought to bring suit against certain oil and natural gas companies operating in the United States in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or that such companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts to their investors or customers.

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. As a result of a recent settlement with certain environmental groups, the FWS, in July 2020, acted on a petition to list the dunes sagebrush lizard finding sufficient information to warrant a formal one-year review to consider listing the species. While that deadline has been missed, the listing review is reportedly ongoing and a decision is expected in June 2023; additionally, FWS has also solicited comments on a proposed conservation agreement that would 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 Biden administration. 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 Biden Administration 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. 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 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 the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have previously been proposed in Congress. Several states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

Federal and state governments have also investigated whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for wastewater disposal wells that impose permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission’s well completion seismicity guidelines for operators in the SCOOP and STACK require hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has previously issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. The Texas Railroad Commission ("TRRC") has adopted similar rules including the indefinite suspension of all deep oil and gas produced water injection wells in certain areas covered by the TRRC’s seismic response program.

Increased regulation of hydraulic fracturing and related activities could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and record keeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services. For more information on each of these items, 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."

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, 2022, we employed approximately 2,000 people, none of which are unionized. All of our employees work for or support our Completion Services reportable segment. Our employees are a key component of our ability to attract and retain customers as a result of their operational excellence in the field.

•Diversity and inclusion. We believe that in order to attract and retain talent with the skill sets and expertise required to maximize our operational efficiencies across all levels in the Company, it is in our best interest to attempt to recruit and develop a diverse team and create a culture that is inclusive and provides equal opportunities for hiring and advancement for all employees and prospective employees. Some examples of this effort include;

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

◦efforts to promote and encourage 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 in partnership with personnel, business parties and other parties directly linked to our operations that share our commitment to these same principles;

◦efforts in our employment practices, including through our code of conduct, our equal employment opportunity employer policy, and our anti-harassment policy; and

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

•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 take actions to mitigate similar incidents from reoccurring in the future. The Company incentivizes 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 2022 annual incentive program were based upon the Company’s achievement of certain safety goals, including a target total recordable incident rate of less than 0.65.

•Professional Development. In 2022, ProPetro launched a leadership training initiative for all positions that are responsible for supervision and oversight of other employees. This effort includes development of 255 frontline and above leadership positions over a seven month period. In 2021, ProPetro introduced a Tuition Reimbursement Program to encourage employees to pursue professional development interests that will help strengthen skills and competencies required for their current position or future roles in the business.

•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.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), are made available free of charge on our internet website at www.propetroservices.com, as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the SEC. The SEC maintains an internet site that contains our reports, proxy and information statements and our other SEC filings. The address of that website is www.sec.gov. Please note that information contained on our website, whether currently posted or posted in the future, is not a part of this Annual Report or the documents incorporated by reference in this Annual Report.

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’ 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. WTI oil price declined significantly in 2015 and 2016 to approximately $30 per barrel, but subsequently recovered in 2017. Furthermore, in March 2020, WTI oil price declined to a low of approximately $20 per barrel and then subsequently recovered. The average WTI oil prices per barrel were approximately $94, $68 and $39 for the years ended December 31, 2022, 2021 and 2020, respectively. In the last three years, the highly volatile and unpredictable nature of 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 WTI oil prices remain highly volatile or decline in the future.

•the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions;

•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 exploration and production;

•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 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;

•operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;

•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;

•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, 2022, 2021 and 2020, approximately 98.3%, 98.7% and 99.5%, respectively, of our revenues were attributable to our operations in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in the Permian Basin caused by significant governmental regulation, processing or transportation capacity constraints, market limitations, curtailment of production or interruption of the processing or transportation of oil and natural gas produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our operations, we could experience any of the same conditions at the same time, resulting in a relatively greater impact on our revenue than they might have on other companies that have more geographically diverse operations.

During 2021 and 2022, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. While the prices of and demand for crude oil have recovered, further outbreaks or the emergence of new strains of the COVID-19 virus, could result in the reimposition of domestic and international regulations directing individuals to stay at home, limiting travel, requiring facility closures and imposing quarantines. Widespread implementation of these or similar restrictions could result in commodity price volatility, reduced demand for our products and services, as well as delays in or inability to fulfill our contractual obligations to customers, logistic constraints, increases in our costs, and workforce and raw material shortages. The effects of the COVID-19 pandemic and related economic, business and market disruptions thus could continue and adversely affect us.

The oilfield services 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 profile. Further, we may face competitive pressure to develop, implement or acquire and deploy certain technology improvements at a substantial cost, such as our DuraStim® fleets or the cost of implementing or purchasing a technology like DuraStim® may be substantially higher than anticipated, and we may not be able to successfully implement the DuraStim® fleets or other technologies we may purchase. As of December 31, 2022 we recorded an impairment of $57.5 million on our DuraStim® equipment because they did not meet our expectations and remained idled with no near term plans to deploy the equipment to customers’ wellsites. 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 services 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 $365.3 million, $165.2 million and $81.2 million during the years ended December 31, 2022, 2021 and 2020. 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 changed from $102.3 million as of December 31, 2022 to approximately $143.3 million as of February 20, 2023 due to a change in our eligible accounts receivable. 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

Concerns over global economic conditions, geopolitical issues (including the Russia-Ukraine war), public health crises (including the COVID-19 pandemic), 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.

•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, is tied to 85.0% to 90.0% of eligible accounts receivable. 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. For example, our borrowing base changed from $102.3 million as of December 31, 2022 to approximately $143.3 million as of February 20, 2023 due to a change in our eligible accounts receivable. 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."

•requiring us to dedicate a substantial portion of our cash flow from operating activities to payments on our indebtedness, thereby reducing the availability of cash flow to fund working capital, capital expenditures, research and development efforts, potential strategic acquisitions and other general corporate purposes;

•limiting our ability to obtain additional financing to fund growth, working capital or capital expenditures, or to fulfill debt service requirements or other cash requirements;

•increasing our vulnerability to economic downturns and changing market conditions; and

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

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®

equipment, which remained idled with no near term plans to deploy the equipment to customers’ wellsites. If oil and natural gas prices trade at depressed price levels as experienced in the first half of 2020, 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 clean‑up 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.

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 91.2%, 91.4% and 97.3% of our consolidated revenue for the years ended December 31, 2022, 2021 and 2020, 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. One customer, Pioneer, accounted for 33.1% of our revenue for the year ended December 31, 2022. The revenue generated from our relationship with Pioneer is largely derived from the A&R Pressure Pumping Services Agreement, which reduced our committed fleet to six through December 31, 2022. On October 31, 2022, we entered into the Fleet One Agreement and the Fleet Two Agreement with Pioneer to provide two committed fleets with terms ranging from eight to twelve month periods. Each agreement was effective January 1, 2023 and is subject to certain termination and release rights. In February 2023, Pioneer provided the Company notice (i) stating that Pioneer intended to release Fleet Two effective upon the completion of operations on the pad where the performance of Services (as defined in the Fleet Two Agreement) is in progress on May 12, 2023 and (ii) requesting that the Company agree to the termination of the Fleet Two Agreement as of the Release Date. The Company agreed with such request, and, as a result, the Fleet Two Agreement will be terminated as of the Release Date. If Pioneer elects to terminate the remaining committed fleet and we are unable to redeploy such fleet to another customer, it could have a material adverse effect on our financial condition, results of operations and cash flows. See "Part I, Item 1. Business — Customers" for further information regarding the agreements with Pioneer.

We enter into purchase agreements with sand suppliers (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 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 Department of Transportation ("DOT"), implementing GHG emissions limits on vehicles manufactured for operation in the United States. In September 2020, the Trump Administration 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 President Biden 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 issued a proposed rule that, if finalized, would establish OOOOb new source and OOOOc first-time existing source of standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair equipment, and reduction of emissions by 95% through capture and control systems. In November 2022, the EPA published a supplemental methane proposal, which, among other items, sets forth specific revisions strengthening the first nationwide emission guidelines for states to limit methane emissions from existing crude oil and natural gas facilities. The proposal 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, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, it is likely that these requirements will 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 President Biden’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 percent from 2020 levels by 2030, including "all feasible reductions" in the energy sector. At COP27 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 US 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. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. However, the impacts of these actions are unclear at this time.

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 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 NDC’s every five years after 2020. Following President Biden’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 COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge; an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. 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, President Biden 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 suspends 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."

There are also increasing financial risks for companies in the fossil fuel sector as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero ("GFANZ") announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it has joined the Network for Greening the Financial System ("NGFS"), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, the Federal Reserve has issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. In January 2023, the Federal Reserve launched a pilot climate scenario analysis exercise, with six of the United States’ largest banks participating to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. Additionally, the United States Securities and Exchange Commission has announced a proposed rule that would require climate disclosures, including registrants’ Scope 1 and 2 emissions and, in some cases, Scope 3 emissions. Although the final form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements. We also cannot predict how financial institutions and investors might consider any information disclosed under the final rule when making investment decisions, and as a result it is possible that we could face increases with respect to the costs of, or restrictions imposed on, our access to capital.

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.

The Tax Cuts and Jobs Act (the "TCJA") included a reduction to the maximum deduction allowed for net operating losses generated in tax years after December 31, 2017, and the elimination of carrybacks of net operating losses. Under the Coronavirus Aid, Relief, and Economic Security Act, or the CARES Act, which modified the TCJA, U.S. federal net operating loss carryforwards ("NOLs") generated in taxable periods beginning after December 31, 2017, may be carried forward indefinitely, but the deductibility of such NOLs in taxable years beginning after December 31, 2020, is limited to 80% of taxable income. As of December 31, 2022, we had approximately $421.7 million of U.S. federal NOLs, some of which will begin to expire in 2035. Approximately $219.5 million of our U.S. federal NOLs relate to pre-2018 periods. As of December 31, 2022, our state net operating losses were approximately $50.4 million and will begin to expire in 2024.

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

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act ("Section 404"). If we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.

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.

Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our shareholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the "DGCL"), our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.

Disclosure concerning legal proceedings is incorporated by reference to "Note 17. Commitments and Contingencies— Contingent Liabilities" of our Consolidated Financial Statements contained in this Annual Report.

On March 22, 2017, we consummated our initial public offering ("IPO") of our common stock at a price of $14.00 per share. Our common stock is traded on the New York Stock Exchange under the symbol "PUMP."

As of December 31, 2022, there were 114,515,008 shares of common stock outstanding, held of record by six holders. The number of record holders of our common stock does not include Depository Trust Company participants or beneficial owners holding shares through nominee names.

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 services 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.

Our hydraulic fracturing operations account for approximately 89.3% of our total revenues and operations. Our total available hydraulic horsepower ("HHP") in our hydraulic fracturing operations at December 31, 2022 was 1,315,000 HHP, which was comprised of 252,500 HHP of our Tier IV DGB equipment and 1,062,500 HHP of conventional Tier II equipment. Our hydraulic fracturing fleets range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsites. 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 capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in September 2021, August 2022 and December 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and purchase of new Tier IV DGB equipment. As such, we entered into conversion and purchase arrangements with our equipment manufacturers for a total of 362,500 HHP of Tier IV DGB equipment and as of December 31, 2022, we have received 192,500 HHP of the converted and new Tier IV DGB equipment and expect to receive the remaining 170,000 HHP by the second quarter of 2023. In August 2022 and December 2022, we entered into three-year electric fleet leases for a total of four fleets with 60,000 HHP per fleet. We expect to take delivery of the electric fleets at different times during the second half of 2023.

On December 31, 2018, we consummated the purchase of pressure pumping and related assets of Pioneer and Pioneer Pumping Services, LLC in the Pioneer Pressure Pumping Acquisition. In connection with the acquisition, we became a long-term service provider to Pioneer under the Pioneer Services Agreement, with a term of up to 10 years for providing pressure pumping and related services, with Pioneer having the right to terminate the agreement, in whole or part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026 and the right to increase the number of committed fleets prior to December 31, 2022. Under the agreement, the Company was entitled to receive compensation if Pioneer were to idle committed fleets ("idle fees"); however, we were first required to use all economically reasonable efforts to deploy the idled fleets to another customer. This agreement was superseded by the agreement below.

On October 31, 2022, we entered into the Fleet One Agreement and the Fleet Two Agreement with Pioneer, pursuant to which we will provide hydraulic fracturing services with two committed fleets, subject to certain termination and release rights. The Fleet One Agreement was effective as of January 1, 2023 and will terminate on August 31, 2023. The Fleet Two Agreement was effective as of January 1, 2023 and was originally planned to terminate on the one year anniversary of the date on which the fleet dedicated thereunder converted from a Tier II diesel Simul-Frac fleet to a Tier IV dual fuel zipper fleet, which was expected to occur in May 2023. In February 2023, Pioneer provided the Company notice (i) stating that Pioneer intended to release Fleet Two effective upon the completion of operations on the pad where the performance of Services (as defined in the Fleet Two Agreement) is in progress on May 12, 2023 and (ii) requesting that the Company agree to the termination of the Fleet Two Agreement as of the Release Date. The Company agreed with such request, and, as a result, the Fleet Two Agreement will be terminated as of the Release Date.

The Russia-Ukraine war, and the adverse impacts of the COVID-19 pandemic in recent years, including inflation, have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing. In 2022, WTI average crude oil price was approximately $94 per barrel, which is the highest average price in the last nine years. We believe that the recent surge in global crude oil prices is partly due to the lack of reinvestment in the oil and gas industry in the last two years, and increased demand for oil and gas products, coupled with the adverse impact of the Russia-Ukraine war, which has led to various sanctions on Russian crude oil supply and businesses. With the significant increase in global crude oil prices, including WTI crude oil prices, there has been an increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of December 2022, according to Baker Hughes. Following the increase in rig count and WTI crude oil price, the oilfield service industry has experienced increased demand for its completion services, and improved pricing. As a result of the growing demand for completion services and significant cost inflation across the industry, we negotiated pricing increases with certain of our customers for our completion services, depending on job design. Although we are currently operating in an improved pricing environment compared to 2020 and 2021, the rapid increase in cost inflation and supply chain tightness could adversely impact our future profitability. The U.S. inflation rate has been steadily increasing since 2021. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including labor costs and equipment. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to timely pass-through the cost increases to our customers, would negatively impact our business, financial condition and results of operations. See Part II, Item 1A. Risk Factors—"Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."

Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including the upstream and oilfield services 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, 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 equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022, and expect to increase to approximately 65% in 2023.

The Permian Basin rig count increase, demand for oil and gas products, WTI crude oil price increase and cost inflation could be indicative of an energy market recovery. If the rig count and market conditions continue to improve, including improved customers' pricing and labor availability, and we are able to continue to meet our customers' lower emissions equipment demands, we believe our operational and financial results will also continue to improve. However, if 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 fleet count was approximately 15 active fleets, a 25% increase from approximately 12 active fleets in 2021;

•we entered into a lease agreement for four electric fleets with 60,000 HHP per fleet, and we transitioned 162,500 HHP of our equipment portfolio to lower emissions, Tier IV DGB equipment. In 2023, our equipment portfolio is expected to be comprised of approximately 65% lower emissions (electric and Tier IV DGB), and 35% conventional diesel equipment;

•we entered into a contract with a customer for the use of one of our electric hydraulic fracturing fleets to provide committed services for a period of three years after we take delivery of the fleet; and

•on November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC, which provides wireline perforation and ancillary services solely in the Permian Basin.

•revenue increased $405.2 million, or 46.3%, to $1,279.7 million, as compared to $874.5 million for the year ended December 31, 2021;

•cost of services (exclusive of depreciation and amortization) increased $220.6 million or 33.3% to $882.8 million, as compared to $662.3 million for the year ended December 31, 2021; cost of services as a percentage of revenue decreased to 69.0% in 2022 compared to 75.7% for the year ended December 31, 2021;

•general and administrative expenses, inclusive of stock-based compensation, increased $28.8 million, or 34.8% to $111.8 million, as compared to $82.9 million for the year ended December 31, 2021;

•the total impairment expense recorded during the year December 31, 2022 was approximately $57.5 million related to our DuraStim® equipment, compared to no impairment expense recorded during the year ended December 31, 2021;

•net income was $2.0 million, compared to a net loss of $54.2 million for the year ended December 31, 2021. Diluted net income per common share was $0.02, compared to diluted net loss per common share of $0.53 for the year ended December 31, 2021. Adjusted EBITDA of approximately $316.6 million increased 134.5%, compared to $135.0 million for the year ended December 31, 2021 (see reconciliation of Adjusted EBITDA to net income (loss) in the subsequent section "How We Evaluate Our Operations") and margins increased 930 basis points;

•our total liquidity was $155.2 million, consisting of cash, cash equivalents and restricted cash of $88.9 million and remaining availability of $66.3 million under our ABL Credit Facility; and

•$30.0 million of borrowings as of December 31, 2022 under our ABL Credit Facility.

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 prices per barrel were approximately $94, $68 and $39 for the years ended December 31, 2022, 2021 and 2020, respectively. In February 2023, the WTI oil price was approximately $78 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 the 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 27.7% and 22.4% of total costs of service for the years ended December 31, 2022 and 2021, respectively. The increase in our direct labor costs percentage is driven by wage adjustments and higher headcount to support current activity levels.

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 33.6%, and 41.8% of total costs of service for the years ended December 31, 2022 and 2021, respectively. The percentage decrease in our expendables in 2022 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 38.7% and 35.8% of total costs of service for the years ended December 31, 2022 and 2021, respectively. The percentage increase in 2022 was primarily driven by higher recurring repairs and maintenance costs in 2022 compared to 2021.

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

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 and our peer group by removing the effects of our capital structure, asset base, nonrecurring (income) expenses 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)During the years ended December 31, 2022, 2021 and 2020, other general and administrative expense (net of reimbursement from insurance carriers) primarily relates to nonrecurring professional fees paid to external consultants in connection with our audit committee review, SEC investigation, shareholder litigation, legal settlement to a vendor and other legal matters, net of insurance recoveries. During the years ended December 31, 2022, 2021

and 2020, we received reimbursement of approximately $10.4 million, $9.8 million and $0.6 million, respectively, from our insurance carriers in connection with the SEC investigation and shareholder litigation.

(2)Includes a $10.7 million net tax refund (net of advisory fees) received in March 2022 from the Texas Comptroller of Public Accounts in connection with limited sales, excise and use tax audit of the period from July 1, 2015 through December 31, 2018.

(3)Includes $2.7 million non-cash income from fixed asset inventory received as part of a settlement of warranty claims with an equipment manufacturer and a $1.6 million unrealized loss on short-term investment.

In 2022, we conducted our business through four operating segments: hydraulic fracturing, cementing, wireline and coiled tubing. For reporting purposes, the hydraulic fracturing, cementing and wireline operating segments are aggregated into our one reportable segment—Completion Services. We disposed of our coiled tubing assets and shut down our coiled tubing operations effective September 1, 2022. The results of our coiled tubing operations prior to September 1, 2022 are reflected in the "All Other" category.

(3)    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 $27.0 million and $9.5 million for the years ended December 31, 2022 and 2021, respectively.

Revenue.  Revenue increased 46.3%, or $405.2 million, to $1,279.7 million for the year ended December 31, 2022, as compared to $874.5 million for the year ended December 31, 2021. Our Completion Services segment revenues increased 47.6%, or $408.6 million for the year ended December 31, 2022, as compared to the year ended December 31, 2021. The increases were primarily attributable to the significant increase in our existing and new customers' activity levels, resulting in higher demand for completion services and improved pricing, and the additional revenue of $31.2 million following the Silvertip Acquisition. The increase in demand for our completion services resulted in an approximately 25% increase in our average effectively utilized fleet count to 15 active fleets in 2022 from 12 active fleets in 2021. Our revenue for the year ended December 31, 2022 included reservation fees charged to a customer of approximately $27.0 million and our revenue for the year ended December 31, 2021 included idle fees charged to a customer of approximately $9.5 million. The increase in these fees was driven by the A&R Pressure Pumping Services Agreement with Pioneer that required six dedicated fleets throughout 2022.

Cost of Services.  Cost of services increased 33.3%, or $220.6 million, to $882.8 million for the year ended December 31, 2022, from $662.3 million during the year ended December 31, 2021. Cost of services in our Completion Services segment increased $221.5 million during the year ended December 31, 2022, as compared to the year ended December 31, 2021. The increases were primarily attributable to the significantly increased activity levels resulting from the increased demand for our services, the Silvertip Acquisition and the impact of general cost inflation. As a percentage of Completion Services segment revenues (including idle fees), Completion Services cost of services decreased to 68.6% for the year ended December 31, 2022, as compared to 75.5% for the year ended December 31, 2021. Excluding idle fees revenue of $27.0 million and $9.5 million for the years ended December 31, 2022 and 2021, respectively, our Completion Services cost of services as a percentage of Completion Services revenues for the years ended December 31, 2022 and 2021 was approximately 70.1% and 76.4%, respectively. The decrease in the percentages was a result of increased operational efficiencies, reduction in operational downtime and improved pricing across our customer base.

General and Administrative Expenses.  General and administrative expenses increased 34.8%, or $28.8 million, to $111.8 million for the year ended December 31, 2022, as compared to $82.9 million for the year ended December 31, 2021. The net increase was primarily attributable to (i) an increase in non-recurring legal expenses (net of insurance recoveries) by $11.1 million incurred primarily in connection with shareholder litigation and settlement with a vendor, (ii) an increase in stock-based compensation expense by $10.4 million, primarily attributable to the non-recurring incremental stock-based compensation associated with the acceleration of stock awards upon resignation of former executives, (iii) an increase in consulting and professional fees by $5.2 million, and (iv) the transaction costs related to the Silvertip Acquisition of approximately $2.2 million, partially offset by a net decrease of approximately $0.1 million in other general and administrative expenses.

Depreciation and Amortization.  Depreciation and amortization decreased 4.0%, or $5.3 million, to $128.1 million for the year ended December 31, 2022, as compared to $133.4 million for the year ended December 31, 2021. The decrease was primarily attributable to the decrease in our fixed asset base as of December 31, 2022, partly attributable to the disposal and impairment of certain fixed assets during the period.

Impairment Expense.  During the year ended December 31, 2022, we recorded $57.5 million in connection with the impairment of our DuraStim® assets, which is included in our Completion Services reportable segment. There was no impairment expense during the year ended December 31, 2021.

Loss on Disposal of Assets.  Loss on the disposal of assets increased 58.0%, or $37.5 million, to $102.1 million for the year ended December 31, 2022, as compared to $64.6 million for the year ended December 31, 2021. The increase was primarily attributable to the divestiture of our coiled tubing operations. We recorded a loss of $13.8 million in connection with the divestiture of our coiled tubing operations. In addition, upon replacement of certain property and equipment, including certain major components like fluid ends and power ends of our completion services equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount is recognized as loss on disposal of assets.

Interest Expense.  Interest expense increased 161.4%, or $1.0 million, to $1.6 million for the year ended December 31, 2022, as compared to $0.6 million for the year ended December 31, 2021. The increase was primarily attributable to the partial write down of unamortized capitalized loan origination cost in connection with the modification to our credit facility and interest on borrowings under our ABL Credit Facility. We had $30.0 million in borrowings under our ABL Credit Facility at the end of 2022 compared to zero at the end of 2021.

Other (Income) Expense.  Other income increased to approximately $11.6 million for the year ended December 31, 2022, as compared to $0.9 million in income for the year ended December 31, 2021. The increase in other income is primarily attributable to the net tax refund to the Company of $10.7 million of sales, excise and use taxes, $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.  Income tax expense was $5.4 million for the year ended December 31, 2022, as compared to income tax benefit of $14.3 million for the year ended December 31, 2021. The reduction in income tax benefit recorded during the year ended December 31, 2022 is primarily attributable to the Company recording pre-tax income in 2022 as compared to pre-tax loss in 2021.

Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility. Our cash is primarily used to fund our operations, support growth opportunities and satisfy future debt payments. Our restricted cash, which was received from a customer will be used solely for the construction or operation of certain electric hydraulic fracturing equipment. Our Borrowing Base (as defined below), as redetermined monthly, is tied to 85.0% to 90.0% of eligible accounts receivable. 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.

As of December 31, 2022, our borrowings under our ABL Credit Facility were $30.0 million and our total liquidity was $155.2 million, consisting of cash, cash equivalents and restricted cash of $88.9 million and $66.3 million of availability under our ABL Credit Facility.

As of February 20, 2023, our borrowings under our ABL Credit Facility were $30.0 million and our total liquidity was approximately $142.8 million, consisting of cash and cash equivalents of $35.4 million and $107.4 million of availability under our ABL Credit Facility.

In 2020 when demand for our services was significantly depressed following the rapidly rising health crisis associated with the COVID-19 pandemic and the energy industry disruptions, the Company experienced a significant decrease in its liquidity. However, with the gradual recovery in the energy industry and the reduced impact of the COVID-19 pandemic, we have seen improvements in the demand for our services and improved pricing, and our liquidity position gradually improved. However, we expect our overall liquidity to decline if we make additional or accelerate our future capital investments. Moreover, the current market conditions may be impacted by increasing interest rates and potential economic slowdown or a new outbreak of a COVID-19 variant or other health crisis, which could negatively impact our future operations, revenue, profitability and cash flows.

The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2022 and 2021, respectively.

Effective April 13, 2022, the Company entered into an amendment and restatement of its revolving credit facility (as amended and restated, the "ABL Credit Facility"). The ABL Credit Facility decreased the borrowing capacity to $150.0 million (subject to the Borrowing Base (as defined below) limit), with the maturity date extended to April 13, 2027. The ABL Credit Facility has a borrowing base of 85% to 90%, depending on the credit ratings of our accounts receivable counterparties, of monthly eligible accounts receivable less customary reserves (the "Borrowing Base"), as redetermined monthly. The Borrowing Base as of December 31, 2022, was approximately $102.3 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) $10.0 million. Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.

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

Capital expenditures incurred were $365.3 million during the year ended December 31, 2022, as compared to $165.2 million during the year ended December 31, 2021. During the year ended December 31, 2022, we increased our capital expenditures to support the increase in our existing and new customers’ activity levels and the transition of our hydraulic fracturing equipment

Our future material use of cash will be to fund our capital expenditures. Capital expenditures for 2023 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 2023, we expect our capital expenditures to range between $250 million to $300 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 on 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 5.43%, and that our ABL Credit Facility debt balance remains the same, our estimated annual interest payment will be $1.6 million.

(2)Operating leases exclude short-term leases and other commitments (see Note 16. Leases and Note 17. Commitments and Contingencies in the financial statements for additional disclosures).

(3)Includes our leases for electric fracturing equipment (240,000 HHP), and power equipment to support electric equipment (70 MW). This equipment is expected to be delivered in 2023.

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

(5)Relates to commitments to purchase Tier IV DGB equipment.

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.

In January 2023, we entered into an equipment lease (the "Power Equipment Lease") for certain power generation equipment. The Power Equipment Lease has not yet commenced. We currently do not control the assets under the lease and have not taken possession of the assets. Therefore, the Company has not accounted for the right of use and lease obligation in its balance sheet as of December 31, 2022. The total estimated contractual commitment in connection with the Power Equipment Lease is approximately $59.6 million.

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 retired certain components of equipment such as fluid ends and power ends, rather than the entire pieces of equipment, and the associated loss is recorded in our statement of operations as part of net loss on disposal of assets, which was $102.1 million, $64.6 million and $58.1 million for the years ended December 31, 2022, 2021 and 2020, respectively.

In accordance with the Financial Accounting Standards Board ("FASB") 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 under‑utilized, 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 off‑setting 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® equipment because it remained idled and there were no near term plans to deploy the DuraStim® equipment to the customers’ wellsite.

In connection with the Silvertip Acquisition, we added $23.6 million of goodwill during the year ended December 31, 2022. There was no write-off of goodwill during the year ended December 31, 2022. We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles—Goodwill and Other, on December 31, 2022, at which time, we determined that the fair value of our wireline reporting unit was substantially in excess of its carrying value. The wireline operating segment is the only segment which has goodwill at December 31, 2022. 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. The carrying value of goodwill in our balance sheet as of December 31, 2022 was $23.6 million.

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. 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 $0.1 million, $0 and $0.4 million, for the years ended December 31, 2022, 2021 and 2020, respectively.

 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, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2023, expressed an unqualified opinion on the Company's internal control over financial reporting.

The Company reviews the carrying value of long-lived assets such as property and equipment and other assets, whenever events or circumstances indicate that the carrying value of long-lived assets may not be recoverable. The Company’s evaluation of the recoverability of assets involves the comparison of undiscounted future cash flows attributable to the asset over the Company’s estimated carrying amount of such asset. As a result of a triggering event for the quarter ended June 30, 2022, management deemed it necessary to assess the recoverability of its DuraStim® hydraulic fracturing equipment. The Company determined that the DuraStim® hydraulic fracturing equipment was impaired and an impairment expense of approximately $57.5 million was recorded for the three months ended June 30, 2022. The estimated fair value of the DuraStim® hydraulic fracturing equipment was determined using the cost approach and significant unobservable inputs, including cost Index curve selection,

We identified the impairment of DuraStim® hydraulic fracturing equipment as a critical audit matter because of the significant estimates and assumptions management makes to evaluate the recoverability of these assets. This required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists, when performing audit procedures to evaluate the reasonableness of management’s assumptions related to cost index curve selection, trend factor calculation, replacement cost, normal useful life, functional obsolescence selection, and minimum percent good.

Our audit procedures related to the fair value of DuraStim® hydraulic fracturing equipment included the following, among others:

•We tested the operating effectiveness of controls over management’s evaluation of the recoverability of long-lived assets.

•With the assistance of our fair value specialists:

–We evaluated the reasonableness of the valuation analysis, including estimates of cost index curve selection, trend factor calculation, replacement cost, normal useful life, functional obsolescence selections, and minimum percent good by (1) evaluating the source information and assumptions used by management, (2) testing the mathematical accuracy of the valuation analysis, and (3) developing independent estimates and comparing our estimates to those used by management.

•We considered any events occurring after the impairment date that may indicate a different valuation for the assets impaired.

•We considered events and circumstances and performed procedures to ensure the accuracy of the triggering event date.

•We tested the effectiveness of controls over business combinations.

•With the assistance of our fair value specialists:

–For property and equipment, we evaluated the reasonableness of the valuation methodology and significant assumptions including estimates of cost index curve selection, trend factor calculation, replacement cost, normal useful life, and minimum percent good 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.

–For intangible assets, we evaluated the reasonableness of the valuation methodology and significant assumptions including discount rate, attrition rate, and royalty rate 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.

–For intangible assets, we evaluated whether the estimated future cash flows used in the income approach were consistent with projections used by the Company, as well as evidence obtained in other areas of the audit

•We considered any events or transactions occurring after the Acquisition date that may indicate a different valuation for the assets acquired and liabilities assumed.

We have audited the internal control over financial reporting of ProPetro Holding Corp. and Subsidiaries (the "Company") as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

(In thousands, except share data)

			2022						2021
ASSETS
CURRENT ASSETS:
Cash, cash equivalents and restricted cash			$	88,862					$	111,918
Accounts receivable - net of allowance for credit losses of $419 and $217, respectively			215,925						128,148
Inventories			5,034						3,949
Prepaid expenses			8,643						6,752
Short-term investment, net			10,283						—
Other current assets			38						297
Total current assets			328,785						251,064
PROPERTY AND EQUIPMENT - Net of accumulated depreciation			922,735						808,494
OPERATING LEASE RIGHT-OF-USE ASSETS			3,147						409
OTHER NONCURRENT ASSETS:
Goodwill			23,624						—
Intangible assets - net of amortization			56,345						—
Other noncurrent assets			1,150						1,269
Total other noncurrent assets			81,119						1,269
TOTAL ASSETS			$	1,335,786					$	1,061,236
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable			$	234,299					$	152,649
Accrued and other current liabilities			49,027						20,767
Operating lease liabilities			854						369
Total current liabilities			284,180						173,785
DEFERRED INCOME TAXES			65,265						61,052
LONG-TERM DEBT			30,000						—
NONCURRENT OPERATING LEASE LIABILITIES			2,308						97
Total liabilities			381,753						234,934
COMMITMENTS AND CONTINGENCIES (Note 17)
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, 114,515,008 and 103,437,177 shares issued, respectively			114						103
Additional paid-in capital			970,519						844,829
Accumulated deficit			(16,600)						(18,630)
Total shareholders’ equity			954,033						826,302
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY			$	1,335,786					$	1,061,236

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2022, 2021 AND 2020

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2022, 2021 AND 2020