FORM 10-K

For the transition period from                      to                     

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes ý  No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).     Yes  ý  No ¨

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

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, 2021, determined using the per share closing price on the New York Stock Exchange Composite tape of $9.16 on that date, was approximately $664.5 million.

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

•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 the rate of inflation;

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

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

•competitive conditions in our industry;

•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;

•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 changes in interest rates) for the Company and our customers;

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

•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;

•changes in our tax status;

•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 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;

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

•the effects of current and future litigation, including the Logan Lawsuit; and

•the potential impact on our business and stock price of any announcements regarding the Logan Lawsuit.

•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.

•Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.

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

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

•New technology may cause us to become less competitive.

•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.

•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.

•We may incur debt and our indebtedness could adversely affect our operations and financial condition.

•We may record losses or impairment charges related to goodwill and long-lived assets.

•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 may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.

•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.

•The Logan Lawsuit could have a material adverse effect on our business, financial condition, results of operation, and cash flows.

•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.

•Increasing trucking regulations may increase our costs and negatively impact our results of operations.

•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.

•The market price of our common stock is subject to volatility.

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

       Our total available HHP at December 31, 2021 was 1,423,000 HHP, which was comprised of 90,000 HHP of our Tier IV Dynamic Gas Blending ("DGB") equipment, 1,225,000 HHP of conventional Tier II equipment and 108,000 HHP of our DuraStim® electric hydraulic fracturing equipment. Our fleet could range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsites. 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 the wellsites. In September 2021, we placed an order with our equipment manufacturers for 125,000 HHP of Tier IV DGB equipment for additional conversions, which we expect to be delivered at different times through the first half of 2022.

          In 2019, we entered into a purchase commitment for 108,000 HHP of DuraStim® electric powered hydraulic fracturing equipment. In addition to DuraStim® fleets, we are also evaluating other electric and alternative pressure pumping solutions. In December 2021, we disposed of our two gas turbines initially purchased to provide electrical power to our DuraStim® fleets as we determined they were an inefficient power solution in the field. In the future, we may lease electrical power equipment from a third party or rely on our customers to provide power solutions for our electric equipment.

         The global public health crisis associated with the COVID-19 pandemic could continue to have an adverse effect on global economic activity for the foreseeable future. Some of the challenges resulting from the COVID-19 pandemic that have impacted our business include restrictions on movement of personnel and associated gatherings, shortage of skilled labor, cost inflation and supply chain disruptions. Additionally, with most of the large, capitalized E&P companies in the United States, including our customers, closely managing their operating budget and exercising capital discipline, we do not currently expect significant increases in crude oil production over the short-to-medium term. Furthermore, OPEC+ has indicated that they will continue with their plans to manage production levels by gradually increasing crude oil output. With the tightness in crude oil production and growing demand for crude oil, there has been a significant increase in rig count and WTI crude oil prices have increased to over $90 per barrel in February 2022 from its lowest point of $20 per barrel in March 2020. The Permian Basin rig count has increased significantly from approximately 179 at the beginning of 2021 to approximately 294 at the end of 2021, according to Baker Hughes. Although crude oil prices are currently at a 7-year high, the oilfield services industry, including the pressure pumping segment, has not fully recovered as evidenced by continued depressed pricing for most of our services, and shortages of skilled labor force in the Permian Basin, coupled with rising inflationary costs. However, we still believe that the Permian Basin, our primary area of operation, will be the most attractive basin to E&P companies and should command higher prices and associated profitability, if the overall demand for crude oil and our services continues to increase.

          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 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. If we are unable to quickly transition to lower emissions equipment and meet our and our customers’ emissions goals, the demand for our services could be adversely impacted.

          The Permian Basin rig count increase, 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 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, 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. Refer to Part II, Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations" for more discussions on our current and future business environment and financial performance.

          We primarily 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 HHP at December 31, 2021 was 1,423,000 HHP, which was comprised of 90,000 HHP of our Tier IV DGB equipment, 1,225,000 HHP of conventional Tier II equipment and 108,000 HHP of our DuraStim® hydraulic fracturing equipment. Our DuraStim® hydraulic fracturing equipment has been tested on a limited scale basis with certain of our customers and we are evaluating the appropriate strategy to continue such field testing, including whether field testing will be conducted in 2022.

          We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment to perform fracturing services. We also refer to all of our fracturing units, other equipment and vehicles necessary to perform a fracturing job as a "fleet" and the personnel assigned to each fleet as a "crew." On average, one hydraulic fracturing fleet consists of approximately 50,000 to 80,000 HHP, depending on job design and customer demand. Our hydraulic fracturing units consist primarily of a high pressure hydraulic pump, diesel or dual gas engine, transmission and various hoses, valves, tanks and other supporting equipment like blenders, irons, hoses and datavans. Our DuraStim® hydraulic fracturing fleet is electrically driven and can be powered by turbines, generators or similar equipment that can generate electricity. In December 2021, we sold our two turbines for cash consideration of $36.0 million, and the net book value of the turbines prior to the sale was approximately $39.5 million. Our two turbines were initially purchased to provide power to our DuraStim® equipment. In the future, we may lease or purchase alternative power solutions for our electric equipment.

          The principal advantages of using coiled tubing include the ability to (i) continue production from the well without interruption, thus reducing the risk of formation damage, (ii) move continuous coiled tubing in and out of a well significantly faster than conventional pipe used with a workover rig, which must be jointed and unjointed, (iii) direct fluids into a wellbore with more precision, allowing for improved stimulation fluid placement, (iv) provide a source of energy to power a downhole motor or manipulate downhole tools, and (v) enhance access to remote fields due to the smaller size and mobility.

          Our customers consist primarily of oil and natural gas producers in North America. Our top five customers accounted for approximately 85.7%, 86.5% and 77.1% of our revenue, for the years ended December 31, 2021, 2020 and 2019, respectively. For the year ended December 31, 2021, Pioneer Natural Resources USA Inc. ("Pioneer") and Endeavor Energy Resources accounted for 54.2% and 14.6%, respectively, of total revenue. No other customer accounted for more than 10% of our total revenue for the year ended December 31, 2021.

          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 Democratic control in both houses of Congress, it is possible that our operations may be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing, permitting and greenhouse gases ("GHG") emissions. We have not experienced any material adverse effect from compliance with current requirements; however, this trend may not continue in the future.

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

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

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

          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. 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 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

          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. For example, the EPA has previously issued a series of rules under the CAA that establish new emission control requirements for certain oil and natural gas production and natural gas processing operations and associated equipment. Separately, the Bureau of Land Management ("BLM") previously finalized a rule governing hydraulic fracturing on federal lands, but that rule was subsequently rescinded. 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, in January 2021, President Biden issued an executive order suspending new leasing activities, but not operations under existing leases, for oil and gas exploration and production on non-Indian federal lands pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters. Although the federal court for the Western District of Louisiana issued a preliminary injunction against the leasing pause, in response to the executive order, the Department of the Interior ("DOI") 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 and, in September 2021, issued a notice to disposal well operators in the Gardendale Seismic Response Area near Midland, Texas to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18 month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. Subsequently, the TRRC ordered the indefinite suspension of all deep oil and gas produced water injection wells in the area, effective December 31, 2021. While we cannot predict the ultimate outcome of these actions, any action that temporarily or permanently restricts the availability of disposal capacity for produced water or other oilfield fluids may increase our customers’ costs or require them to suspend operations, which may adversely impact demand for our products and services.

          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, 2021, we employed approximately 1,500 people, none of which are unionized. Of the total population over 80% of our headcount worked for or supports our pressure pumping 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 2021 annual incentive program were based upon the Company’s achievement of certain safety goals, including a target total recordable incident rate of less than 0.75.

•Professional Development. 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. This program is designed to provide assistance and offset related training expense.

•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. Since the beginning of COVID-19, we have implemented processes and procedures to help address COVID-19 matters. Below are some of the adjustments we made to address the COVID-19 pandemic;

◦instituted periodic update, guidelines and questionnaires to all employees to address and identify COVID-19 related matters;

◦initially instituted a temporary remote work environment in response to COVID-19 and have retained the flexibility for employees to work remotely when necessary or advisable;

◦encouraged all employees to adhere to guidelines provided by the Centers for Disease Control and Prevention; and

◦provided coverage for COVID-19 testing and vaccination under the Company’s medical plan at no cost to our employees.

          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 web site 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 web site 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 hydraulic fracturing 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 $68, $39 and $57 for the years ended December 31, 2021, 2020 and 2019, respectively. Recently, WTI oil price reached a 7-year high of over $90 per barrel in February 2022. 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 equipment, including the supply and demand for lower emissions hydraulic fracturing 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, 2021, 2020 and 2019, approximately 98.7%, 99.5% and 99.4%, 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.

          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 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 pressure pumping 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. 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 $165.2 million, $81.2 million and $400.7 million during the years ended December 31, 2021, 2020 and 2019. 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 $61.1 million as of December 31, 2021 to approximately $79.0 million as of February 18, 2022 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 means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.

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.

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% 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 $61.1 million as of December 31, 2021 to approximately $79.0 million as of February 18, 2022 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 addition, our DuraStim® equipment remains under evaluation and has yet to be commercialized. If we are not able to successfully commercialize the DuraStim® equipment, and are not able to deploy the equipment for alternative uses, we will incur impairment losses on the carrying value of the DuraStim® equipment. As of December 31, 2021, the carrying value of our DuraStim® equipment is approximately $90 million. 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. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer‑owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability

          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 91.4%, 97.3% and 95.5% of our consolidated revenue for the years ended December 31, 2021, 2020 and 2019, 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 54.2% of our revenue for the year ended December 31, 2021. The revenue generated from our relationship with Pioneer is largely derived from pressure pumping and related services provided pursuant to the Pressure Pumping Services Agreement (the "Pioneer Services Agreement"). Although the Pioneer Services Agreement provides for the provision of services for a term of up to 10 years, Pioneer has the right to terminate the Pioneer Services Agreement in its sole discretion, in whole or part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026. While management believes our relationship with Pioneer will continue beyond December 31, 2022, if Pioneer elects to terminate the Pioneer Services Agreement effective December 31, 2022, or seeks to renegotiate the terms on which we provide services to Pioneer, it could have a material adverse effect on our financial condition, results of operations and cash flows.

          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.

          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.

          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. Additionally, the United States Securities and Exchange Commission has announced an intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

          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, 2021, we had approximately $408.0 million of federal NOLs, some of which will begin to expire in 2035. Approximately $219.5 million of our federal NOLs relate to pre-2018 periods. As of December 31, 2021, our state net operating losses were approximately $50.1 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 15. 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, 2021, there were 103,437,177 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.

          The quarterly changes for the periods shown in the following graph are based on the assumption that $100 had been invested in our common stock, the Russell 2000 Index ("Russell 2000") and a self-constructed peer group index of comparable companies ("Peer Group") on March 17, 2017 (the first trading date of our common stock), and that all dividends were reinvested at the closing prices of the dividend payment dates. The relevant companies included in our Peer Group consists of Liberty Oilfield Services Inc., Nextier Oilfield Solutions Inc., RPC, Inc., Calfrac Well Services Ltd., Patterson-UTI Energy, Inc. and Mammoth Energy Services, Inc. Subsequent measurement points are the last trading days of each quarter. The total cumulative dollar returns shown on the graph represent the value that such investments would have had on the last trading date of 2021. The calculations exclude trading commissions and taxes. The stock price performance on the following graph and table is not necessarily indicative of future stock price performance.

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 subsidiary.

          We are a Midland, Texas‑based oilfield services company providing hydraulic fracturing and other complementary 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 hydraulic fracturing services in the region by HHP.

          Our total available HHP at December 31, 2021 was 1,423,000 HHP, which was comprised of 90,000 HHP of our Tier IV DGB equipment, 1,225,000 HHP of conventional Tier II equipment and 108,000 HHP of our DuraStim® electric hydraulic fracturing equipment. Our fleet could range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsites. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at the wellsites. In September 2021, we placed an order with our equipment manufacturers for 125,000 HHP of Tier IV DGB equipment for additional conversions, which we expect to be delivered at different times through the first half of 2022.

          In 2019, we entered into a purchase commitment for 108,000 HHP of DuraStim® electric powered hydraulic fracturing equipment. In addition to DuraStim® fleets, we are also evaluating other electric and alternative pressure pumping solutions. In December 2021, we disposed of our two gas turbines initially purchased to provide electrical power to our DuraStim® fleets but as determined they were an inefficient power solution in the field. In the future, we may lease electrical power equipment from a third party or rely on our customers to provide power solutions for our electric equipment.

          The global public health crisis associated with the COVID-19 pandemic could continue to have an adverse effect on global economic activity for the foreseeable future. Some of the challenges resulting from the COVID-19 pandemic that have impacted our business include restrictions on movement of personnel and associated gatherings, shortage of skilled labor, cost inflation and supply chain disruptions. Additionally, with most of the large, capitalized E&P companies in the United States, including our customers, closely managing their operating budget and exercising capital discipline, we do not currently expect significant increases in crude oil production over the short-to-medium term. Furthermore, OPEC+ has indicated that they will continue with their plans to manage production levels by gradually increasing crude oil output. With the tightness in crude oil production and growing demand for crude oil, there has been a significant increase in rig count and WTI crude oil prices have increased to over $90 per barrel in February 2022 from its recent lowest point of $20 per barrel in March 2020. The Permian Basin rig count has increased significantly from approximately 179 at the beginning of 2021 to approximately 294 at the end of 2021, according to Baker Hughes. Although crude oil prices are currently

          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 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. If we are unable to quickly transition to lower emissions equipment and meet our and our customers’ emissions goals, the demand for our services could be adversely impacted.

          The Permian Basin rig count increase, 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 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, 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.

•although we gradually captured improved pricing during the year, the recent energy industry disruption and impact of COVID-19 pandemic continued to adversely impact overall demand for and pricing of our services;

•we experienced rapidly increasing inflationary cost resulting from labor and supply chain tightness, which negatively impacted our profitability and cash flows;

•our average effectively utilized fleet count was approximately 12 active fleets, a 20% increase from approximately 10 active fleets in 2020;

•we transitioned 90,000 HHP of our equipment portfolio to lower emissions, Tier IV DGB equipment. In 2022, we plan to convert an additional 125,000 HHP to Tier IV DGB equipment, with total conversion costs expected to approximate $74 million; and

•we continued to test and develop, alongside the equipment manufacturer, our existing DuraStim® equipment.

•revenue increased $85.3 million, or 10.8%, to $874.5 million, as compared to $789.2 million for the year ended December 31, 2020, primarily a result of the increase in demand for pressure pumping services following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity;

•cost of services (exclusive of depreciation and amortization) increased $78.0 million or 13.3% to $662.3 million, as compared to $584.3 million for the year ended December 31, 2020, primarily a result of our higher utilization and activity levels, following the rebound from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity in 2020; cost of services as a percentage of revenue increased to 75.7% in 2021 compared to 74.0% for the year ended December 31, 2020;

•general and administrative expenses, inclusive of stock-based compensation, decreased $3.8 million, or 4.4% to $82.9 million, as compared to $86.8 million for the year ended December 31, 2020;

•no impairment expense recorded during the year December 31, 2021, compared to $38.0 million during the year ended December 31, 2020;

•net loss was $54.2 million, compared to a net loss of $107.0 million for the year ended December 31, 2020. Diluted net loss per common share was $0.53, compared to diluted net loss per common share of $1.06 for the year ended December 31, 2020. Adjusted EBITDA was approximately $135.0 million, compared to $141.5 million for the year ended December 31, 2020 (see reconciliation of Adjusted EBITDA to net income in the subsequent section "How We Evaluate Our Operations");

•generated cash of approximately $36.0 million from the sale of our two turbines in December 2021;

•our total liquidity was $169.3 million, consisting of cash of $111.9 million and remaining availability of $57.4 million under our ABL Credit Facility; and

•no debt as of December 31, 2021 under our ABL Credit Facility.

◦Growth Capital: our operations were driven by more dedicated work from our customers. Our capital expenditure program was focused on maintaining existing dedicated demand for our equipment. We reduced capital investment in speculative growth.

◦Other Expenditures: we strategically managed our maintenance program in line with our projected activity levels. We continued to seek lower pricing and cost saving measures for our expendable items, materials used in day-to-day operations and large component replacement parts. In addition, with the supply chain disruptions, we worked closely with our vendors to better plan our future needs and accelerated purchases of certain components and spare parts;

◦Labor Force: we implemented several strategies including pay adjustments of approximately 8% to retain and attract skilled workforce that will support our operations;

◦Working Capital: we have negotiated more favorable payment terms with certain of our larger vendors, strategically disposed of certain assets to improve our liquidity position and continue to actively manage our portfolio of accounts receivables; and

◦Customer Pricing: we continue to have ongoing pricing conversations with our customers to permit us to earn an appropriate return on our equipment and capital investments and to cover rising inflationary cost resulting from the impact of COVID-19 on labor force, supply chain and our operations in general.

          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 $68, $39 and $57 for the years ended December 31, 2021, 2020 and 2019, respectively. In February 2022, the WTI oil price was over $90 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 22.4% and 22.7% of total costs of service for the years ended December 31, 2021 and 2020, respectively.

          Expendables. Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our pressure pumping 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 41.8%, and 37.6% of total costs of service for the years ended December 31, 2021 and 2020, respectively. The percentage increase in our expendable product cost in 2021 was primarily attributable to the increase in our activity levels and higher freight cost.

          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 hydraulic fracturing fleet and other 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 35.8% and 39.7% of total costs of service for the years ended December 31, 2021 and 2020, respectively. The percentage decrease in 2021 was primarily driven by most of our customers directly sourcing diesel and pricing improvement.

          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 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, 2021, 2020 and 2019, 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 and shareholder litigation, net of insurance recoveries. During the years ended December 31, 2021, 2020 and 2019, we received reimbursement of approximately $9.8 million, $0.6 million and $0, respectively, from our insurance carriers in connection with the SEC investigation and shareholder litigation.

(2)    Inclusive of stock‑based compensation of $11.5 million and $9.1 million for 2021 and 2020, respectively.

(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 idle fees of $9.5 million and $47.2 million for the years ended December 31, 2021 and 2020, respectively.

Revenue.  Revenue increased 10.8%, or $85.3 million, to $874.5 million for the year ended December 31, 2021, as compared to $789.2 million for the year ended December 31, 2020. Our pressure pumping segment revenues increased 10.9%, or $84.2 million for the year ended December 31, 2021, as compared to the year ended December 31, 2020. The increases were primarily attributable to the significant increase in demand for pressure pumping services, following the rebound from the depressed oil prices and slowdown in economic activity resulting from the COVID-19 pandemic. The increase in demand for our pressure pumping services resulted in an approximate 20% increase in our average effectively utilized fleet count to approximately 12 active fleets in 2021 from 10 active fleets in 2020. Included in our revenue for the years ended December 31, 2021 and 2020 was revenue generated from idle fees charged to a certain customer of approximately $9.5 million and $47.2 million, respectively.

Revenues from services other than pressure pumping increased 7.1%, or approximately $1.1 million, for the year ended December 31, 2021, as compared to the year ended December 31, 2020. The increase in revenues from services other than pressure pumping during the year ended December 31, 2021, was primarily attributable to the increase in utilization experienced in our coiled tubing operations, which was driven by increased E&P completions activity following the rebound from the depressed oil prices and impact of the COVID-19 pandemic.

Cost of Services.  Cost of services increased 13.3%, or $78.0 million, to $662.3 million for the year ended December 31, 2021, from $584.3 million during the year ended December 31, 2020. Cost of services in our pressure pumping segment increased $77.1 million during the year ended December 31, 2021, as compared to the year ended December 31, 2020. The increases were primarily attributable to our higher utilization and activity levels, following the rebound from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity in 2020. As a percentage of pressure pumping segment revenues (including idle fees), pressure pumping cost of services increased to 75.5% for the year ended December 31, 2021, as compared to 73.8% for the year ended December 31, 2020. Excluding idle fees revenue of $9.5 million and $47.2 million for the years ended December 31, 2021 and 2020, respectively, our pressure pumping cost of services as a percentage of pressure pumping revenues for the years ended December 31, 2021 and 2020 was approximately 76.4% and 78.5%, respectively. The decrease was a result of increased customer activity levels, which is consistent with our increased fleet utilization, coupled with significant pricing pressure in 2020.

General and Administrative Expenses.  General and administrative expenses decreased 4.4%, or $3.8 million, to $82.9 million for the year ended December 31, 2021, as compared to $86.8 million for the year ended December 31, 2020. The net decrease was primarily attributable to the decrease in (i) nonrecurring advisory and professional fees of $19.4 million, which was primarily attributable to the Company's expanded audit committee internal review, SEC investigation and shareholder litigation, (ii) legal and professional fees of $3.9 million, which was partially offset by net increases of (iii) $15.8 million in payroll expenses, (iv) $2.4 million of stock based compensation expense, (v) $1.2 million in insurance expense and (vi) $0.1 million in other remaining general and administrative expenses.

Depreciation and Amortization.  Depreciation and amortization decreased 13.0%, or $19.9 million, to $133.4 million for the year ended December 31, 2021, as compared to $153.3 million for the year ended December 31, 2020. The decrease was primarily attributable to the overall decrease in our fixed asset base as of December 31, 2021, partly attributable to the impairment of certain fixed assets in 2020.

Impairment Expense.  There was no impairment expense during the year ended December 31, 2021. During the year ended December 31, 2020, the depressed market conditions, crude oil prices and negative near-term outlook for the utilization of certain of our equipment, resulted in the Company recording an impairment expense of approximately $38.0 million, of which $9.4 million related to goodwill impairment and $28.6 million related to property and equipment impairment. The substantial portion of our impairment expense in 2020 related to our pressure pumping segment.

Loss on Disposal of Assets.  Loss on the disposal of assets increased 11.2%, or $6.5 million, to $64.6 million for the year ended December 31, 2021, as compared to $58.1 million for the year ended December 31, 2020. The increase was primarily attributable to an increase in utilization resulting from an increase in the operational intensity of our equipment during 2021. Upon sale or retirement of property and equipment, including certain major

Interest Expense.  Interest expense decreased 74.2%, or $1.8 million, to $0.6 million for the year ended December 31, 2021, as compared to $2.4 million for the year ended December 31, 2020. The decrease in interest expense was primarily attributable to a decrease in our financing arrangements and zero debt in 2021, compared to 2020. Our interest expense consist primarily of amortization of our original loan cost. In 2021, we have zero debt under our ABL Credit Facility.

Other Expense (Income).  Other income increased to approximately $0.9 million for the year ended December 31, 2021, as compared to $0.9 million in expense for the year ended December 31, 2020. The increase in other income is primarily attributable to the net refund of approximately $2.1 million to the Company from a sales and excise and use tax audit and partially offset by an expense related to our lender's commitment fees during the year ended December 31, 2021, as compared to the year ended December 31, 2020.

Income Tax Benefit.  Income tax benefit was $14.3 million for the year ended December 31, 2021, as compared to income tax benefit of $27.5 million for the year ended December 31, 2020. The reduction in income tax benefit recorded during the year ended December 31, 2021 is primarily attributable to the Company projecting a much lower pre-tax loss in 2021 as compared to that in 2020. Furthermore, there was no significant change in the effective tax rate from 20.8% during the year ended December 31, 2021, compared to 20.4% during the year ended December 31, 2020.

          Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our revolving credit facility ("ABL Credit Facility"). Our cash is primarily used to fund our operations, support growth opportunities and satisfy debt payments, if any. Our borrowing base, as redetermined monthly, is tied to 85.0% of eligible accounts receivable (the "borrowing base"). Our borrowing base as of December 31, 2021 was approximately $61.1 million and was approximately $79.0 million as of February 18, 2022. Changes to our operational activity 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. We believe our remaining monthly availability under our ABL Credit Facility will be adversely impacted if oil and gas market conditions decline in the future.

          As of December 31, 2021, we had no borrowings under our ABL Credit Facility and our total liquidity was $169.3 million, consisting of cash and cash equivalents of $111.9 million and $57.4 million of availability under our ABL Credit Facility.

          As of February 18, 2022, we had no borrowings under our ABL Credit Facility and our total liquidity was approximately $151.3 million, consisting of cash and cash equivalents of $76.0 million and $75.3 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 increase in demand for our services in 2021, our liquidity position has gradually improved and this improvement has continued into the beginning of 2022, as market conditions have continued to improve, although we expect our overall liquidity to decline during 2022 as we make additional capital investments. Moreover, the current market conditions resulting from the COVID-19 pandemic have and may in the future change rapidly and there could be a new outbreak of a COVID-19 variant that could result in travel restrictions, business closure and institution of quarantining and/or other activity restrictions, which could negatively impact our future operations, revenue, profitability and cash flows if not contained or if the vaccines currently distributed and administered to people are not as effective as anticipated in curbing the spread of any such new COVID-19 variant.

          Net cash provided by operating activities was $154.7 million for the year ended December 31, 2021, as compared to $139.1 million for the year ended December 31, 2020. The net increase of $15.6 million was primarily due to the reduction in our net loss, resulting from an increase in our activity levels in 2021, and the rebound from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted our

operations in 2020. The net increase in cash provided by operating activities was also slightly impacted by the timing of our receivable collections from our customers and payment to our vendors.

          Net cash used in investing activities increased to $104.3 million for the year ended December 31, 2021, from $94.2 million for the year ended December 31, 2020. The net increase in our cash used in investing activities was primarily attributable to our investment in Tier IV DGB equipment. Included in our net cash used for investing activities in 2021 was a cash payment of $45.3 million for new Tier IV DGB equipment. The remaining cash payments in 2021 were incurred in connection with our maintenance capital expenditures and other growth initiatives. Our cash flow from investing activities was partially offset by $36.0 million of cash generated from the sale of our two turbine generators in December 2021.

          Our ABL Credit Facility, as amended, has a total borrowing capacity of $300 million (subject to the borrowing base limit), with a maturity date of December 19, 2023. The ABL Credit Facility has a borrowing base of 85% of monthly eligible accounts receivable less customary reserves. The borrowing base as of December 31, 2021 was approximately $61.1 million. The ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size or the Borrowing Base or (ii) $22.5 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.

           As of December 31, 2021, we had no borrowings outstanding under our ABL Credit Facility.

          Our future material use of cash will be to fund our capital expenditures. Capital expenditures for 2022 are projected to be primarily related to maintenance capital expenditures to support our existing pressure pumping assets, costs to convert some existing equipment to lower emissions pressure pumping 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 2022, we expect our capital expenditures to range between $250.0 million to $300.0 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 fleet 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.

In addition, we have option agreements with our equipment manufacturer to purchase an additional 108,000 HHP of DuraStim® hydraulic fracturing equipment through July 31, 2022.

(1)As of December 31, 2021, we had no borrowings under our ABL Credit Facility. If we decide to borrow from our ABL Credit Facility in the future, interest expense will be charged based on the agreed contractual interest rates. However, we are obligated to pay agency and commitment fees on unused balance which could be up to approximately $1.2 million annually, depending on our utilization of the ABL Credit Facility.

(2)Operating leases exclude short-term leases and other commitments (see Note 14. Leases and Note 15. Commitments and Contingencies in the financial statements for additional disclosures).

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

          Disclosure concerning recently issued accounting standards is incorporated by reference to "Note 2- Significant Accounting Policies" of our Consolidated Financial Statements contained in this Annual Report.

          We primarily 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 $64.6 million, $58.1 million and $106.8 million for the years ended December 31, 2021, 2020 and 2019, 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 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.

          Our DuraStim® equipment is yet to be commercialized. If we are not able to successfully commercialize the DuraStim® equipment, and are not able to deploy the equipment for alternative uses, we will incur impairment losses on the carrying value of the DuraStim® equipment. As of December 31, 2021, the carrying value of our DuraStim® equipment is approximately $90 million.

          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 (increase)/decrease in pre‑tax (loss)/income of approximately $0, $0.4 million and $1.3 million, for the years ended December 31, 2021, 2020 and 2019, 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, 2021, 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 25, 2022, expressed an unqualified opinion on the Company's internal control over financial reporting.

•We evaluated the completeness of related-party transactions by obtaining the Company’s list of related-party relationships and transactions and performing the following:

◦Comparing it to public filings, external news, third-party information or research reports, questionnaires completed by the Company’s directors and officers, and other sources.

◦Searching for potential related-party transactions within the accounts receivable, accounts payable, and vendor listings master files and journal entries by searching for the name, vendor identification numbers, and customer identification numbers of the related parties.

◦Inspecting the Company’s minutes from meetings of the Board of Directors and related committees.

◦Making inquiries of executive officers, key members of management, and the Audit Committee of the Board of Directors regarding related party transactions.

          We have audited the internal control over financial reporting of ProPetro Holding Corp. and Subsidiary (the "Company") as of December 31, 2021, 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, 2021, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.

          We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021, of the Company and our report dated February 25, 2022, expressed an unqualified opinion on those consolidated financial statements.

          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.

          We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

          A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

          Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019

PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019