EDGAR 10-K Filing

Company CIK: 1680247
Filing Year: 2022
Filename: 1680247_10-K_2022_0001680247-22-000007.json

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ITEM 1. BUSINESS
Item 1. Business.
Our Company
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 exploration and production ("E&P") of North American oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region’s most active and well-capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil-producing areas in the United States, and we believe we are one of the leading providers of hydraulic fracturing services in the region by hydraulic horsepower ("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 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.
Our competitors include many large and small oilfield services companies, including Halliburton Company, Liberty Oilfield Services Inc., Nextier Oilfield Solutions Inc., Patterson-UTI Energy Inc., RPC, Inc., FTS International Inc. and a number of private and locally-oriented businesses. The markets in which we operate are highly competitive. To be successful, an oilfield services company must provide services that meet the specific needs of oil and natural gas E&P companies at competitive prices. Competitive factors impacting sales of our services are price, reputation, technical expertise, emissions profile, service and equipment design and quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in E&P companies' criteria in choosing a service provider. However, we have recently observed the energy industry and our customers shift to lower emissions equipment, which we believe will be an increasingly important factor in an E&P company's selection of a service provider. The transition to lower emissions equipment has been challenging for companies in the service industry because of the capital requirements, and the depressed pricing experienced by the service industry. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our operational efficiencies, productivity, equipment quality, reliability, ability to manage multifaceted logistics challenges, commitment to safety and the ability of our people to handle the most complex Permian Basin well completions.
Our substantial market presence in the Permian Basin positions us well to capitalize on drilling and completion activity in the region. Primarily, our operational focus has been in the Permian Basin's Midland sub-basin, where our customers have operated. However, we have recently increased our operations in the Delaware sub-basin and are well-positioned to support further increases to our activity in this area in response to demand from our customers. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.
Through our pressure pumping segment (which also includes our cementing operations), we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. Our hydraulic fracturing fleet has been designed to handle the operating conditions commonly utilized in the Permian Basin and the region's increasingly high-intensity well completions (including Simul-Frac, which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well.
In addition to our core pressure pumping segment operations, which includes our cementing operations, we also offer coiled tubing services. Through our coiled tubing services segment, we seek to create operational efficiencies for our customers, which could allow us to capture a greater portion of their capital spending across the lifecycle of a well.
Commodity Price and Other Economic Conditions
The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control.
The 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.
Our Services
We have historically conducted our business through three operating segments: hydraulic fracturing, cementing, and coiled tubing. For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into one reportable segment-"Pressure Pumping". Our coiled tubing operating segment and corporate administrative expense are aggregated into our "All Other" segment. For additional financial information on our reportable segments, please see reportable segment information in Part II - Item 8, "Financial Statements and Supplementary Data."
Pressure Pumping
Hydraulic Fracturing
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.
The hydraulic fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, which in our business are comprised primarily of sand, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to break, or loosen viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures created, thereby increasing the mobility of the hydrocarbons. As a result of the fracturing process, production rates are usually enhanced substantially, thus increasing the rate of return of hydrocarbons for the operator.
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.
We provide dedicated equipment, personnel and services that are tailored to meet each of our customer’s needs. Each fleet has a designated team of personnel, which allows us to provide responsive and customized services, such as project design, proppant and other consumables procurement, real-time data provision and post-completion analysis for each of our jobs. Many of our hydraulic fracturing fleets and associated personnel have worked continuously with the same customer for the past several years promoting deep relationships and a high degree of coordination and visibility into future customer activity levels. Furthermore, in light of our substantial market presence and historically high fleet utilization levels, we have established a variety of trusted relationships with key equipment, sand and other downhole consumable suppliers. We believe these strategic relationships position us to acquire equipment, parts and materials on a timely and economic basis and allow our dedicated procurement and logistics team to support consistently safe and reliable operations.
Cementing
We provide cementing services for completion of new wells and remedial work on existing wells. Cementing services use pressure pumping equipment to deliver a slurry of liquid cement that is pumped down a well between the casing and the borehole. Cementing provides isolation between fluid zones behind the casing to minimize potential damage to hydrocarbon bearing formations or the integrity of freshwater aquifers, and provides structural integrity for the casing by securing it to the earth. Cementing is also done when re-completing wells, where one zone is plugged and another is opened.
We believe that our cementing segment provides an organic growth opportunity for us to expand our service offerings within our existing customer base.
Other Services
Coiled Tubing
Coiled tubing services involve injecting coiled tubing into wells to perform various completion well intervention operations. Coiled tubing is a flexible steel pipe with a diameter of typically less than three inches and manufactured in continuous lengths of thousands of feet. It is wound or coiled on a truck-mounted reel for onshore applications. Due to its small diameter, coiled tubing can be inserted into existing production tubing and used to perform a variety of services (including drillout of plugs) to enhance the flow of oil or natural gas.
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
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.
Competition
The markets in which we operate are highly competitive. To be successful, an oilfield services company must provide services that meet the specific needs of oil and natural gas E&P companies at competitive prices. Competitive factors impacting sales of our services are price, reputation, technical expertise, emissions profile, service and equipment design and quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in E&P companies’ criteria in choosing a service provider. However, we have recently observed the energy industry and our customers shift to lower emissions equipment, which we believe will be an increasingly important factor in an E&P company’s selection of a service provider. The transition to lower emissions equipment has been challenging for companies in the oilfield service industry because of the capital requirements and the continuing depressed pricing experienced by the service industry. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our operational efficiencies, productivity, equipment quality, reliability, ability to manage multifaceted logistics challenges, commitment to safety and the ability of our people to handle the most complex Permian Basin well completions.
We provide our services primarily in the Permian Basin, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield services companies, including the largest integrated oilfield services companies. Our major competitors for hydraulic fracturing services include Halliburton Company, Liberty Oilfield Services Inc., Nextier Oilfield Solutions Inc., Patterson-UTI Energy Inc., RPC, Inc., FTS International, Inc. and a number of private and locally-oriented businesses.
Seasonality
Our results of operations have historically reflected seasonal tendencies, generally in the fourth quarter, relating to the conclusion of our customers’ annual capital expenditure budgets, the holidays and inclement winter weather during which we may experience declines in our operating results.
Operating Risks and Insurance
Our operations are subject to hazards inherent in the oilfield services industry, such as accidents, blowouts, explosions, fires and spills and releases that can cause personal injury or loss of life, damage or destruction of property, equipment, natural resources and the environment and suspension of operations.
In addition, claims for loss of oil and natural gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.
Our business involves the transportation of heavy equipment and materials, and as a result, we may also experience traffic accidents which may result in spills, property damage and personal injury.
Despite our efforts to maintain safety standards, we have suffered accidents from time to time in the past and anticipate that we could experience accidents in the future. In addition to the property damage, personal injury and other losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees, regulatory agencies and other parties. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.
We maintain commercial general liability, workers’ compensation, business automobile, commercial property, umbrella liability, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry. Further, we have pollution legal liability coverage for our business entities, which would cover, among other things, third party liability and costs of clean up relating to environmental contamination on our premises while our equipment is in transit and on our customers’ job site. With respect to our hydraulic fracturing operations, coverage would be available under our pollution legal liability policy for any surface or subsurface environmental clean-up and liability to third parties arising from any surface or subsurface contamination. We also have certain specific coverages for some of our businesses, including our hydraulic fracturing services.
We maintain directors and officers insurance; however, our insurance coverage is subject to certain exclusions (including, for example, any required SEC disgorgement or penalties) and we are responsible for meeting certain deductibles under the policies. Moreover, we cannot assure you that our insurance coverage will adequately protect us from claims made in the Logan Lawsuit or any future claims.
Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See “Risk Factors” for a description of certain risks associated with our insurance policies.
Environmental and Occupational Health and Safety Regulations
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.
Below is an overview of some of the more significant environmental, health and safety requirements with which we must comply. Our customers’ operations are subject to similar laws and regulations. Any material adverse effect of these laws and regulations on our customers’ operations and financial position may also have an indirect material adverse effect on our operations and financial position.
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
vehicles manufactured for operation in the United States. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOO(b) new source and OOOO(c) first-time existing source of standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair equipment, and reduction of emissions by 95% through capture and control systems. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year.
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.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products.
Moreover, climate change may result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in the meteorological and hydrological patterns, that could adversely impact us, our customers’ and our suppliers’ operations. Such physical risks may result in damage to our customers’ facilities or otherwise adversely impact our operations, such as if facilities are subject to water use curtailments in response to drought, or demand for our customers’ products, such as to the extent warmer winters reduce the demand for energy for heating purposes, which may ultimately reduce demand for the products and services we provide. Such physical risks may also impact our suppliers, which may adversely affect out ability to provide our products and services. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured.
Endangered and Threatened Species. Environmental laws such as the Endangered Species Act ("ESA") and analogous state laws may impact exploration, development and production activities in areas where we operate. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and various state analogs. The U.S. Fish and Wildlife Service ("FWS") may identify previously unidentified endangered or threatened species or may designate
critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. For example, the dunes sagebrush lizard, which is found only in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas (including areas where our customers operate), was a candidate species for listing under the ESA by the FWS for many years. As a result of a recent settlement with certain environmental groups, the FWS, in July 2020, acted on a petition to list the dunes sagebrush lizard finding sufficient information to warrant a formal one-year review to consider listing the species. While that deadline has been missed, the listing review is reportedly ongoing; additionally, FWS has also solicited comments on a proposed conservation agreement that would implement certain protective practices for the species and authorize incidental take of the species resulting from certain covered activities, including exploration and development of oil and gas fields. However, to the extent any protections are implemented for this or any other species, it could cause us or our customers to incur additional costs or become subject to operating restrictions or operating bans in the affected areas.
Regulation of Hydraulic Fracturing and Related Activities. Our hydraulic fracturing operations are a significant component of our business. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. 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.
Increased regulation of hydraulic fracturing and related activities could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and record keeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services.
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.
Human Capital
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.
Some examples of significant programs and initiatives that are focused to attract, develop and retain our diverse workforce include:
•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.
In 2021, we performed an extensive review of our health-related benefits program to ensure that our offerings are market competitive and effectively utilized by employees. Based on that review, we made comprehensive adjustments to our health-related benefits programs, which improved the cost and quality of coverage. We significantly increased the number of employee meetings to provide education and encourage individuals to maximize the value of benefits offered, resulting in an overall increase in participation and positive feedback from employees.
We have also recently initiated a plan to review our 401(k) plan and implement improvements in 2022 with a focus on improving plan structure, reducing program administration, providing employee education and increasing plan participation.
Availability of Filings
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.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors.
The following is a description of significant factors that could cause actual results to differ materially from those contained in forward-looking statements made in this Annual Report and presented elsewhere by management from time to time. Such factors may have a material adverse effect on our business, financial condition and results of operations. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all our potential risks or uncertainties. Due to these, and other factors, past performance should not be considered an indication of future performance.
Risks Inherent in Our Business and Industry
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.
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.
Many factors over which we have no control affect the supply of, and demand for our services, and our customers’ willingness to explore, develop and produce oil and natural gas, and therefore, influence prices for our services, including:
•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.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in 2020, Saudi Arabia and Russia failed to agree on a plan to cut production of oil and gas within OPEC and Russia. Subsequently, Saudi Arabia announced plans to increase production and reduce the prices at which they sell oil. These events, combined with the COVID-19 pandemic that has negatively impacted the economic activity and disrupted the supply chains of certain of our customers, have contributed to the unpredictable nature of crude oil prices.
The cyclical nature of the oil and natural gas industry may cause our operating results to fluctuate.
We derive our revenues from companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices. We have experienced, and may in the future experience, significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, the decline in and unpredictable nature of oil and gas prices in 2019 and 2020, combined with adverse changes in the capital and credit markets and the COVID-19 pandemic in 2020, caused many exploration and production companies to significantly reduce their 2020 and 2021 capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies can charge for their services. These factors have materially and adversely affected our business, results of operations and financial condition. In addition, a majority of the service revenue we earn is based upon a charge for a relatively short period of time (for example, a day, a week or a month) for the actual period of time the service is provided to our customers. By contracting services on a short-term basis, we are exposed to the risks of a rapid reduction in market prices and utilization and resulting volatility in our revenues.
Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business.
We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or any other communicable disease, or any other public health crisis, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees. For example, in response to COVID-19, we made adjustments to some of our business processes that helped and will continue to help address the impact to the COVID-19 pandemic.
The COVID-19 pandemic has spread across the globe and impacted financial markets and worldwide economic activity and adversely affected our operations in the recent years. In addition, the effects of COVID-19 across the globe have negatively impacted the domestic and international demand for crude oil and natural gas, which has contributed to price volatility, impacted the operations and activity levels of our customers and materially and adversely affected the demand for oilfield services. These factors also negatively impacted our current suppliers and their ability or willingness to provide the necessary equipment, parts or raw materials, and they may fail to deliver the products timely and in the quantities required. Any resulting delays or restrictions from COVID-19 on the provision of our services could have a material adverse effect on our business, financial condition, results of operations and cash flows. As the potential impact from COVID-19 is difficult to predict, the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. Any potential impact will depend on future developments and new information that may emerge regarding the COVID-19 infection rate or the efficacy and distribution of COVID-19 vaccines, and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could adversely affect our business, results of operations and financial condition.
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 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.
Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.
A prolonged economic slowdown or recession in the United States, adverse events relating to the energy industry or regional, national and global economic conditions and factors, particularly a further slowdown in the exploration and production industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased exploration and development spending by our customers, decreased demand for oil and natural gas and decreased prices for oil and natural gas. In 2020, the COVID-19 pandemic and the turmoil between the members of OPEC+ caused oil prices to fall substantially and adversely impacted the global economy; a recurrence of similar events would heighten the risk of a prolonged economic slowdown or recession in the United States.
New technology may cause us to become less competitive.
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.
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.
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.
Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, geopolitical issues, public health crises (including the COVID-19 pandemic), interest rates, inflation, the availability and cost of credit in the United States and foreign financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, could
precipitate an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. The historically unpredictable nature of oil and natural gas prices, and particularly the volatility over the past two years have caused a reduction in our customers’ spending and associated drilling and completion activities, which had and may continue to have an adverse effect on our revenue and cash flows. If the economic climate in the United States or abroad deteriorates or remains uncertain, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and adversely impact our results of operations, liquidity and financial condition.
Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.
Our existing and future indebtedness, whether incurred in connection with acquisitions, operations or otherwise, may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on such indebtedness as payments become due. Our level of indebtedness may affect our operations in several ways, including the following:
• increasing our vulnerability to general adverse economic and industry conditions;
• the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;
• our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
• any failure to comply with the financial or other debt covenants, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;
• our level of debt could impair our ability to obtain additional financing, or obtain additional financing on favorable terms in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and
• our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.
Restrictions in our ABL Credit Facility 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.
The operating and financial restrictions and covenants in our credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our ABL Credit Facility restricts or limits our ability to:
•grant liens;
•incur additional indebtedness;
•engage in a merger, consolidation or dissolution;
•enter into transactions with affiliates;
•sell or otherwise dispose of assets, businesses and operations;
•materially alter the character of our business as currently conducted; and
•make acquisitions, investments and capital expenditures.
Furthermore, our ABL Credit Facility contains certain other operating and financial covenants. Our ability to comply with the covenants and restrictions contained in the ABL Credit Facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our ABL Credit Facility, a significant portion of our indebtedness may become immediately due and
payable and our lenders’ commitment to make further loans to us may terminate. Further, our borrowing base, as redetermined monthly, is tied to 85.0% 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."
We may incur debt and our indebtedness could adversely affect our operations and financial condition.
Our business is capital intensive and we may seek to raise debt capital to fund our business and growth strategy. Indebtedness could have negative consequences that could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects, such as:
•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.
Furthermore, interest rates on future indebtedness could be higher than current levels, causing our financing costs to increase accordingly. In addition, LIBOR and other “benchmark” rates are subject to ongoing national and international regulatory scrutiny and reform. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of June 2023 for US dollars setting. At this time, no consensus exists as to what rate or rates may become acceptable alternatives to LIBOR and we are unable to predict the effect of any such alternatives on our business and results of operations. However, if LIBOR is phased out without a replacement benchmark, our only option under the ABL Credit Facility will be to borrow at the Base Rate (as defined in the ABL Credit Facility) until an alternative benchmark rate is selected. Changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on the price of our shares, our ability to issue equity or incur debt.
We may record losses or impairment charges related to goodwill and long-lived assets.
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.
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.
Our operations are exposed to the risks inherent to our industry, such as equipment defects, vehicle accidents, worksite injuries to our or third-party personnel, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, pipe or pipeline failures, abnormally pressured formations and various environmental hazards, such as oil
spills and releases of, and exposure to, hazardous substances. For example, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including hydrochloric acid and other chemical additives. In addition, our operations are exposed to potential natural disasters, including blizzards, tornadoes, storms, floods, other adverse weather conditions and earthquakes. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties or other damage resulting in curtailment or suspension of our operations or the loss of customers. The cost of managing such risks may be significant. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues.
Our insurance may not be adequate to cover all losses or liabilities we may suffer. We are also self-insured up to $10 million per occurrence for certain losses arising from or attributable to fire and/or explosion at the wellsites. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In addition, sub-limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our business, results of operations and financial condition. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position.
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.
A terrorist attack, armed conflict or political or civil unrest could harm our business.
Terrorist activities, anti-terrorist efforts, other armed conflicts and political or civil unrest could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants, refineries or transportation facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our services. Terrorist activities, the threat of potential terrorist activities, political or civil unrest and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.
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 operate with most of our customers under master service agreements ("MSAs"). We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer-owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability
falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.
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.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and process and record operational and accounting data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings indicating that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary information, personal information and other data, or other disruption of our business operations. In addition, certain cyber incidents, such as unauthorized surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks, including cyberattacks, may not be sufficient and may not protect against or cover all of the losses we may experience as a result of the realization of such risks. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate the effects of cyber incidents.
We may grow through acquisitions and our failure to properly plan and manage those acquisitions may adversely affect our performance.
We have completed and may in the future pursue, asset acquisitions or acquisitions of businesses. Any acquisition of assets or businesses involves potential risks, including the failure to realize expected profitability, growth or accretion; environmental or regulatory compliance matters or liability; title or permit issues; the incurrence of significant charges, such as impairment of goodwill, or property and equipment or restructuring charges; and the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate. The process of upgrading acquired assets to our specifications and integrating acquired assets or businesses may also involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount of time and resources and may divert management’s attention from existing operations or other priorities.
We must plan and manage any acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. Any failure to manage acquisitions effectively or integrate acquired assets or businesses into our existing operations successfully, or to realize the expected benefits from an acquisition or minimize any unforeseen operational difficulties, could have a material adverse effect on our business, financial condition, prospects or results of operations.
The Logan Lawsuit could have a material adverse effect on our business, financial condition, results of operation, and cash flows.
In September 2019, a complaint, captioned Richard Logan, Individually and On Behalf of All Others Similarly Situated, Plaintiff, v. ProPetro Holding Corp., et al., (the "Logan Lawsuit"), was filed against the Company and certain of its then current and former officers and directors in the U.S. District Court for the Western District of Texas.
In July 2020, the Logan Lawsuit Lead Plaintiffs Nykredit Portefølje Administration A/S, Oklahoma Firefighters Pension and Retirement System, Oklahoma Law Enforcement Retirement System, Oklahoma Police Pension and Retirement System, and Oklahoma City Employee Retirement System, and additional named plaintiff Police and Fire Retirement System of the City of Detroit, individually and on behalf of a putative class of shareholders who purchased the Company’s common stock between March 17, 2017 and March 13, 2020, filed a third amended class action complaint in the U.S. District Court for the Western District of Texas, alleging violations of Sections 10(b) and 20(a) of the Exchange Act, as amended, and Rule l0b-5 promulgated thereunder, and Sections 11 and 15 of the Securities Act of 1933, as amended, based on allegedly inaccurate or misleading statements, or omissions of material facts, about the Company’s business, operations and prospects against the Company, certain former officers and current and former directors. On September 13, 2021, the Court partially granted and partially denied motions to dismiss filed by the Company and the individual defendants. Discovery is still ongoing.
In May 2020, the U.S. District Court for the Western District of Texas consolidated two shareholder derivative lawsuits previously filed against the Company and certain of its current and former officers and directors into a single lawsuit captioned In re ProPetro Holding Corp. Derivative Litigation (the "Shareholder Derivative Lawsuit"). In August
2020, the plaintiffs in the Shareholder Derivative Lawsuit filed a consolidated complaint alleging (i) breaches of fiduciary duties, (ii) unjust enrichment and (iii) contribution. The plaintiffs did not quantify any alleged damages in their complaint but, in addition to attorneys’ fees and costs, they seek various forms of relief, including (i) damages sustained by the Company as a result of the alleged misconduct, (ii) punitive damages and (iii) equitable relief in the form of improvements to the Company’s governance and controls. On September 15, 2021, the Court granted the Company's motion to dismiss the complaint in its entirety, without prejudice.
On November 19, 2021, the Company received a demand letter from a law firm representing one of the purported shareholders of the Company that previously filed the dismissed Shareholder Derivative Lawsuit. The demand letter alleged facts and claims substantially similar to the Shareholder Derivative Lawsuit. The Board of Directors has constituted a committee to evaluate the demand letter and recommend a course of action to the Board of Directors, and the committee has retained counsel to assist with its review. The committee’s review is ongoing.
We are presently unable to predict the duration, scope or result of the Logan Lawsuit or any other related lawsuit or investigation. As of December 31, 2021, no provision was made by the Company in connection with this pending lawsuit as the final outcome cannot be reasonably estimated.
The ongoing Logan Lawsuit and any related future litigation give rise to risks and uncertainties that could adversely affect our business, results of operations and financial condition. Such risks and uncertainties include, but are not limited to, uncertainty as to the scope, timing and ultimate outcome of the lawsuit, including the potential impact to the Company in the event of an adverse outcome and on the market price of the Company’s common stock; the costs and expenses of the Logan Lawsuit including legal fees and possible settlement in the event of an adverse outcome; the risk of additional potential litigation or regulatory action arising from matters relating to this lawsuit.
The outcome of the Logan Lawsuit and any other litigation is necessarily uncertain. We could be forced to expend significant resources in the defense of this lawsuit or future ones, and we may not prevail.
We maintain director and officer insurance; however, our insurance coverage is subject to certain exclusions (including, for example, any required SEC disgorgement or penalties) and we are responsible for meeting certain deductibles under the policies. Moreover, we cannot assure you that our insurance coverage will adequately protect us from claims made in the Logan Lawsuit. Further, as a result of the pending litigation and investigation the costs of insurance may increase and the availability of coverage may decrease. As a result, we may not be able to maintain our current levels of insurance at a reasonable cost, or at all.
Risks Related to Customers, Suppliers and Competition
Reliance upon a few large customers may adversely affect our revenue and operating results.
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 face significant competition that may cause us to lose market share, and competition in our industry has intensified during the industry downturn.
The oilfield services industry is highly competitive and has relatively few barriers to entry. The principal competitive factors impacting sales of our services are price, reputation and technical expertise, equipment and service quality and health and safety standards. The market is also fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. For instance, our larger competitors may offer services at below-market prices or bundle ancillary services at no additional cost to our customers. We compete with large national and multi-national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis.
Some jobs are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment may be further intensified by tighter emissions standards in the energy industry and mergers and acquisitions among oil and natural gas companies or other events that have the effect of reducing the number of available customers. As a result of competition, we may lose customers or customer work and lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. The amount of equipment available may exceed demand, which could result in active price competition. In addition, some exploration and production companies have commenced completing their wells using their own hydraulic fracturing equipment and personnel. Any increase in the development and utilization of in-house fracturing capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.
Pressure on pricing for our services resulting from the industry downturn has impacted, and may continue to impact, our ability to maintain utilization and pricing for our services or implement price increases. During periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our results of operations. Also, we may not be able to successfully increase prices without adversely affecting our utilization levels. The inability to maintain our utilization and pricing levels, or to increase our prices as costs increase, could have a material adverse effect on our business, financial condition and results of operations.
Furthermore, competition among oilfield services and equipment providers is affected by each provider’s reputation for safety and quality. We cannot assure that we will be able to maintain our competitive position.
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 condition.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use the production could have a material adverse effect on our business, results of operations and financial condition. In weak economic environments, we may experience increased delays and failures to pay due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets or other sources of capital. The unpredictable nature of oil and gas prices in recent years and the economic disruption from the COVID-19 pandemic may have negatively impacted the financial condition and liquidity of some of our customers, and future declines or continued volatility could impact their ability to meet their financial obligations to us. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, results of operations, and financial condition.
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 purchase specialized equipment, parts and raw materials (including, for example, frac sand, chemicals and fluid ends) from third party suppliers and affiliates. In some cases, our customers are responsible for supplying necessary raw
materials (including frac sand), parts and/or equipment. At times during the business cycle, there is a high demand for hydraulic fracturing and other oilfield services and extended lead times to obtain equipment and raw materials needed to provide these services. For example, in 2021, we have seen significant disruption in supply chains around the world caused by the COVID-19 pandemic that have impacted our operations. Should our current suppliers (or our customers’ suppliers where applicable) be unable or unwilling to provide the necessary equipment, parts or raw materials or otherwise fail to deliver the products timely and/or in the quantities required, any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, future price increases for this type of equipment, parts and raw materials could negatively impact our ability to purchase new equipment, to update or expand our existing fleets, to timely repair equipment in our existing fleets or meet the current demands of our customers.
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 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.
Risks Related to Employees
We rely on a few key employees whose absence or loss could adversely affect our business.
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.
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.
The delivery of our services requires skilled and qualified workers with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield services industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a less challenging work environment at wage rates that are competitive. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled workers. As a result of the COVID-19 pandemic, we have experienced difficulties in attracting and retaining skilled workers. If demand for our services increases, we may experience difficulty in hiring or re-hiring skilled and unskilled workers in the future to meet that demand. At times, the demand for skilled workers in our geographic areas of operations is high, and the supply is limited. As a result, competition for experienced oilfield services personnel is intense, and we face significant challenges in competing for crews and management with large and well-established competitors. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. Furthermore, if we are unable to adjust wages to account for rapidly rising inflationary cost, there could be a reduction in the available skilled labor force we could attract or retain. If any of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
Risks Related to Regulatory Matters
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.
The nature of our operations, including the handling, storing, transporting and disposing of a variety of fluids and substances, including hydraulic fracturing fluids, which can contain substances such as hydrochloric acid, and other regulated substances, air emissions and wastewater discharges exposes us to some risks of environmental liability, including the release of pollutants from oil and natural gas wells and associated equipment to the environment. The cost of compliance with these laws can be significant. Failure to properly handle, transport or dispose of these materials or
otherwise conduct our operations in accordance with these and other environmental laws could expose us to substantial liability for administrative, civil and criminal penalties, cleanup and site restoration costs and liability associated with releases of such materials, damages to natural resources and other damages, as well as potentially impair our ability to conduct our operations. Such liability is commonly on a strict, joint and several liability basis, without regard to fault. Liability may be imposed as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other third parties may file claims against us for personal injury or property damage allegedly caused by the release of pollutants into the environment. Environmental laws and regulations have changed in the past, and they may change in the future and become more stringent. For example, following the election of President Biden and Democratic control in both houses of Congress, President Biden has made climate change a focus of his administration. For more information, see our risk factor titled, “Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.” Separately, current and future claims and liabilities may have a material adverse effect on us because of potential adverse outcomes, defense costs, diversion of management resources, unavailability of insurance coverage and other factors. The ultimate costs of these liabilities are difficult to determine and may exceed any reserves we may have established. If existing environmental requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.
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.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate future GHG emissions. As a result, our operations as well as the operations of our oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
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 and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segment from the oil and natural gas source category and rescinded the methane-segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOO(b) new source and OOOO(c) first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair requirement, and reduction of emissions by 95% through capture and control systems. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored "Paris Agreement," requires member states to submit non-binding, individually-determined reduction goals known as NDC’s every five years after 2020. Following President Biden’s executive order in January 2021, the United States rejoined the Paris Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. Additionally, at the COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge; an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. However, the impacts of these actions are unclear at this time.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate-change-related pledges made by certain
candidates for public office. On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on climate-related risk across government agencies and economic sectors. The executive order also suspends the issuance of new leases for oil and gas development on federal land; for more information, see our 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 LNG export facilities, or more restrictive GHG emissions limitations for oil and gas facilities. Litigation risks are also increasing as a number of cities and other local governments 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.
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 adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products. Additionally, political, litigation and financial risks may result in our oil and natural gas customers restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation
Moreover, climate change may result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact us, our customers’ and our suppliers’ operations. Such physical risks may result in damage to our customers’ facilities or otherwise adversely impact our operations, such as if facilities are subject to water use curtailments in response to drought, or demand for our customers’ products, such as to the extent warmer winters reduce the demand for energy for heating purposes, which may ultimately reduce demand for the products and services we provide. Such physical risks may also impact our suppliers, which may adversely affect our ability to provide our products and services. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Our hydraulic fracturing operations are a significant component of our business, and it is an important and common practice that is used to stimulate production of hydrocarbons, particularly oil and 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 emissions of volatile organic compounds and methane from certain oil and natural gas production and natural gas processing operations and equipment. Separately, the BLM finalized a rule governing hydraulic fracturing on federal lands but this 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 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 been proposed in recent sessions of 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 in 2014 that imposed certain 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 released 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 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
Increased regulation of hydraulic fracturing and related activities could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services.
Increasing trucking regulations may increase our costs and negatively impact our results of operations.
In connection with our business operations, including the transportation and relocation of our hydraulic fracturing equipment and shipment of frac sand, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the DOT and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials. Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the DOT. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Certain motor vehicle operators require registration with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria that could result in a suspension of operations.
Increased attention to environmental, social and governance (“ESG”) matters, conservation measures, commercial development and technological advances could reduce demand for oil and natural gas and our services.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, increased attention to climate change and other ESG matters, and technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The commercial development of economically-viable alternative energy sources and related products (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could have a similar effect. In addition, certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development, including the allowance of percentage depletion for oil and natural gas properties, may be eliminated as a result of proposed legislation. Any future decreases in the rate at which oil and natural gas reserves are discovered or developed, whether due to the passage of legislation, increased governmental regulation leading to limitations, or prohibitions on exploration and drilling activity, including hydraulic fracturing, or other factors, could have a material adverse effect on our business and financial condition, even in a stronger oil and natural gas price environment.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, certain statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, we may announce various targets or product and service offerings in an attempt to improve our ESG profile. However, we cannot guarantee that we will be able to meet any such targets or that such targets or offerings will have the intended results on our ESG profile, including but not limited to as a result of unforeseen costs, consequences or technical difficulties associated with such targets or offerings. Also, despite any voluntary actions, we may receive pressure from certain investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals or policies, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Additionally, to the extent ESG matters negatively impact our
reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.
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.
Water is an essential component of unconventional shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Over the past several years, certain of the areas in which we and our customers operate have experienced extreme drought conditions and competition for water in such areas is growing. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. For instance, some states require E&P companies to report certain information regarding the water they use for hydraulic fracturing and to monitor the quality of groundwater surrounding some wells stimulated by hydraulic fracturing. Generally, our water requirements are met by our customers from sources on or near their sites, but there is no assurance that our customers will be able to obtain a sufficient supply of water from sources in these areas. Our or our customers’ inability to obtain water from local sources or to effectively utilize flowback water could have an adverse effect on our financial condition, results of operations and cash flows.
Risks Related to our Tax Matters
Our ability to use our net operating loss carryforwards may be limited.
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.
We are required to comply with certain provisions of Section 404, which requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control.
If we or our auditors identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and
require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows.
Certain provisions of our certificate of incorporation, and bylaws, as well as Delaware law, may discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our 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 business could be negatively affected as a result of the actions of activist shareholders.
Publicly traded companies have increasingly become subject to campaigns by investors seeking to increase shareholder value by advocating corporate actions such as financial restructuring, increased borrowing, special dividends, stock repurchases, sales of assets or even sale of the entire company. Given our shareholder composition and other factors, it is possible such shareholders or future activist shareholders may attempt to effect such changes or acquire control over us. Responding to proxy contests and other actions by such activist shareholders or others in the future would be costly and time-consuming, disrupt our operations and divert the attention of our Board and senior management from the pursuit of business strategies, which could adversely affect our results of operations and financial condition. Additionally, perceived uncertainties as to our future direction as a result of shareholder activism or changes to the composition of the Board may lead to the perception of a change in the direction of our business, instability or lack of continuity which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our business, financial condition, revenues, results of operations and cash flows could be adversely affected.
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to pursue actions in another judicial forum for disputes with us or our directors, officers, employees or agents.
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.
The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.
The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our certificate of incorporation to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws.
Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation regarding exclusive forum. This choice of forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
The market price of our common stock is subject to volatility.
The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading of our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our limited trading volume, the concentration of holdings or our common stock, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets, volatility in oil and gas prices and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this report. Significant sales of our common stock, or the expectation of these sales, by significant shareholders, officers or directors could materially and adversely affect the market price of our common stock.
There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
We are not restricted from issuing additional common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market, or the perception that these sales could occur, could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments.
None.

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ITEM 2. PROPERTIES
Item 2. Properties
Our corporate headquarters is located at 1706 S. Midkiff, Midland, Texas 79701. In addition to our headquarters, we also own and lease other properties that are used for field offices, yards or storage in the Permian Basin. We believe that our facilities are adequate for our current operations.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings.
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.
From time to time, we may be subject to various other legal proceedings and claims incidental to or arising in the ordinary course of our business.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine and Safety Disclosures
None.
Part II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
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”.
Holders
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.
Dividend
We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business and repay borrowings under our ABL Credit Facility, if any. Our future dividend policy is within the discretion of our Board and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our Board may deem relevant. In addition, our ABL Credit Facility places certain restrictions on our ability to pay cash dividends.
Performance Graph
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.
Date Peer Group Russell 2000 ProPetro Holding Corp.
3/17/2017 $ 100.0 $ 100.0 $ 100.0
3/31/2017 $ 97.0 $ 100.1 $ 88.9
6/30/2017 $ 93.2 $ 102.6 $ 96.3
9/29/2017 $ 105.2 $ 108.4 $ 99.0
12/29/2017 $ 114.3 $ 112.0 $ 139.0
3/29/2018 $ 91.0 $ 111.9 $ 109.6
6/29/2018 $ 86.9 $ 120.6 $ 108.1
9/28/2018 $ 85.1 $ 124.9 $ 113.7
12/31/2018 $ 52.9 $ 99.7 $ 85.0
3/31/2019 $ 65.2 $ 114.2 $ 155.4
6/30/2019 $ 47.5 $ 116.6 $ 142.8
9/30/2019 $ 35.1 $ 113.8 $ 62.7
12/31/2019 $ 38.8 $ 125.1 $ 77.6
3/31/2020 $ 9.7 $ 86.8 $ 17.2
6/30/2020 $ 16.2 $ 108.9 $ 35.5
9/30/2020 $ 15.5 $ 114.3 $ 28.0
12/31/2020 $ 23.8 $ 150.1 $ 51.0
3/31/2021 $ 29.5 $ 169.2 $ 73.5
6/30/2021 $ 35.4 $ 176.5 $ 63.2
9/30/2021 $ 31.9 $ 168.8 $ 59.7
12/31/2021 $ 27.5 $ 172.4 $ 55.9

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
You should read the following discussion and analysis of our financial condition and results of operations together with our audited consolidated financial statements and the related notes included in this Annual Report. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report, including information with respect to our plans and strategy for our business and related financing, includes forward-looking statements that involve risks and uncertainties. You should read the "Risk Factors" section of this Annual Report for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.
Basis of Presentation
This discussion of our results of operations omits our results of operations for the year ended December 31, 2019 and the comparison of our results of operations for the years ended December 31, 2020 and 2019, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on March 5, 2021.
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.
Overview
Our Business
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.
Our substantial market presence in the Permian Basin positions us well to capitalize on drilling and completion activity in the region. Primarily, our operational focus has been in the Permian Basin's Midland sub-basin, where our customers have operated. However, we have recently increased our operations in the Delaware sub-basin and are well-positioned to support further increases to our activity in this area in response to demand from our customers. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.
Through our pressure pumping segment (which also includes our cementing operations), we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. Our hydraulic fracturing fleet has been designed to handle the operating conditions commonly utilized in the Permian Basin and the region's increasingly high-intensity well completions (including Simul-Frac, which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well.
In addition to our core pressure pumping segment operations, which includes our cementing operations, we also offer coiled tubing services. Through our coiled tubing services segment, we seek to create operational efficiencies for our customers, which could allow us to capture a greater portion of their capital spending across the lifecycle of a well.
Pioneer Pressure Pumping Acquisition
On December 31, 2018, we consummated the purchase of pressure pumping and related assets of Pioneer and Pioneer Pumping Services, LLC in the Pioneer Pressure Pumping Acquisition. The pressure pumping assets acquired included hydraulic fracturing pumps of 510,000 HHP, four coiled tubing units and the associated equipment maintenance facility. In connection with the acquisition, we became a long-term service provider to Pioneer under the Pioneer Services Agreement, providing pressure pumping and related services for a term of up to 10 years; provided, that Pioneer has the right to terminate the Pioneer Services Agreement, in whole or part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026. Pioneer can increase the number of committed fleets prior to December 31, 2022. Pursuant to the Pioneer Services Agreement, the Company is entitled to receive compensation if Pioneer were to idle committed fleets ("idle fees"); however, we are first required to use all economically reasonable efforts to deploy the idled fleets to another customer. At the present, we have eight fleets committed to Pioneer. During times when there is a significant reduction in overall demand for our services, the idle fees could represent a material portion of our revenues.
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 future financial condition, results of operations and cash flows.
Commodity Price and Other Economic Conditions
The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control.
The 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
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 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.
Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to the holiday season, inclement winter weather and exhaustion of our customers' annual budgets. As a result, we typically experience declines in our operating and financial results in November and December, even in a stable commodity price and operations environment.
2021 Operational Highlights
Over the course of the year ended December 31, 2021:
•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.
2021 Financial Highlights
Financial highlights for the year ended December 31, 2021:
•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.
Actions to Address the Economic Impact of COVID-19
Since March 2020, we initiated several actions to mitigate the anticipated adverse economic conditions for the immediate future and to support our financial position, liquidity and the efficient continuity of our operations as follows:
◦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.
Our Assets and Operations
Through our pressure pumping segment, which includes cementing operations, we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. Our hydraulic fracturing fleets have been designed to handle Permian Basin specific operating conditions and the region’s increasingly high-intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. We plan to continually reinvest in our equipment to ensure optimal performance and reliability.
In addition to our core pressure pumping segment operations, we also offer a suite of complementary well completion and production services, including coiled tubing and other services. We believe these complementary services create operational efficiencies for our customers and could allow us to capture a greater portion of their capital spending across the lifecycle of a well in the future.
How We Generate Revenue
We generate revenue primarily through our pressure pumping segment, and more specifically, by providing hydraulic fracturing services to our customers. We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment to perform fracturing services. We also provide personnel and services that are tailored to meet each of our customers’ needs. We charge our customers on a per-job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant and chemicals to be used and other parameters of the job. We also could generate revenue from idle fees from our customers in certain circumstances when committed fleets are idled.
In addition to hydraulic fracturing services, we generate revenue through the complementary services that we provide to our customers, including cementing, coiled tubing and other related services. These complementary services are provided through various contractual arrangements, including on a turnkey contract basis, in which we set a price to perform a particular job, or a daywork contract basis, in which we are paid a set price per day for our services. We are also sometimes paid by the hour for these complementary services.
Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil 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.
The historical weekly average Permian Basin rig count based on the Baker Hughes Company rig count information was as follows:
Year Ended December 31,
Drilling Rig Type (Permian Basin) 2021 2020 2019
Directional 2 1 5
Horizontal 227 212 405
Vertical 11 8 32
Total 240 221 442
Average Permian Basin rig count to U.S rig count 50.5 % 51.0 % 46.9 %
Costs of Conducting our Business
The principal direct costs involved in operating our business are direct labor, expendables and other direct costs.
Direct Labor Costs. Payroll and benefit expenses related to our crews and other employees that are directly or indirectly attributable to the effective delivery of services are included in our operating costs. Direct labor costs amounted to 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.
How We Evaluate Our Operations
Our management uses Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.
Adjusted EBITDA and Adjusted EBITDA Margin
We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our earnings, before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock-based compensation, and (iii) other unusual or nonrecurring (income)/expenses, such as impairment charges, severance, costs related to asset acquisitions, insurance recoveries, costs related to SEC investigation and class action lawsuits and one-time professional and advisory fees. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.
Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, and research analysts, to assess our financial performance because it allows us and other users to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization), nonrecurring (income) expenses and items outside the control of our management team (such as income taxes). Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered as an alternative to net income (loss), operating income (loss), cash flow from operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles in the United States of America ("GAAP").
Note Regarding Non-GAAP Financial Measures
Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP ("non-GAAP"), except when specifically required to be disclosed by GAAP in the financial statements. We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure, asset base, nonrecurring (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.
Reconciliation of net (loss) income to Adjusted EBITDA ($ in thousands):
Pressure
Pumping
All Other
Total
Year ended December 31, 2021
Net loss $ (12,723) $ (41,462) $ (54,185)
Depreciation and amortization
129,478 3,899 133,377
Interest expense
- 614 614
Income tax benefit - (14,252) (14,252)
Loss (gain) on disposal of assets 64,903 (257) 64,646
Stock-based compensation
- 11,519 11,519
Other income - (873) (873)
Other general and administrative expense (1)
- (6,471) (6,471)
Severance expense 30 602 632
Adjusted EBITDA
$ 181,688 $ (46,681) $ 135,007
Pressure
Pumping All Other Total
Year ended December 31, 2020
Net loss $ (68,271) $ (38,749) $ (107,020)
Depreciation and amortization
148,659 4,631 153,290
Interest expense
1 2,382 2,383
Income tax benefit - (27,480) (27,480)
Loss on disposal of assets
56,659 1,477 58,136
Impairment expense 36,907 1,095 38,002
Stock-based compensation
- 9,100 9,100
Other expense
- 874 874
Other general and administrative expense (1)
- 13,038 13,038
Retention bonus and severance expense 75 1,065 1,140
Adjusted EBITDA
$ 174,030 $ (32,567) $ 141,463
Pressure
Pumping All Other Total
Year ended December 31, 2019
Net income (loss)
$ 281,090 $ (118,080) $ 163,010
Depreciation and amortization
139,348 5,956 145,304
Interest expense
51 7,090 7,141
Income tax expense - 50,494 50,494
Loss on disposal of assets
106,178 633 106,811
Impairment expense - 3,405 3,405
Stock-based compensation
- 7,776 7,776
Other expense
- 717 717
Other general and administrative expense (1)
- 25,208 25,208
Deferred IPO bonus, retention bonus and severance expense 7,093 2,110 9,203
Adjusted EBITDA
$ 533,760 $ (14,691) $ 519,069
____________________
(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 $0, respectively, from our insurance carriers in connection with the SEC investigation and shareholder litigation.
Results of Operations
We conduct our business through three operating segments: hydraulic fracturing, cementing and coiled tubing. For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into our one reportable segment-pressure pumping.
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
($ in thousands, except percentages)
Year Ended December 31, Change
2021 2020 Variance %
Revenue $ 874,514 $ 789,232 $ 85,282 10.8 %
Less (Add):
Cost of services (1)
662,266 584,279 77,987 13.3 %
General and administrative expense (2)
82,921 86,768 (3,847) (4.4) %
Depreciation and amortization 133,377 153,290 (19,913) (13.0) %
Impairment expense - 38,002 (38,002) (100.0) %
Loss on disposal of assets 64,646 58,136 6,510 11.2 %
Interest expense 614 2,383 (1,769) (74.2) %
Other expense (income) (873) 874 1,747 199.9 %
Income tax benefit (14,252) (27,480) (13,228) (48.1) %
Net loss $ (54,185) $ (107,020) $ (52,835) (49.4) %
Adjusted EBITDA (3)
$ 135,007 $ 141,463 $ (6,456) (4.6) %
Adjusted EBITDA Margin (3)
15.4 % 17.9 % (2.5) % (14.0) %
Pressure pumping segment results of operations:
Revenue $ 857,642 $ 773,474 $ 84,168 10.9 %
Cost of services $ 647,570 $ 570,442 $ 77,128 13.5 %
Adjusted EBITDA $ 181,688 $ 174,030 $ 7,658 4.4 %
Adjusted EBITDA Margin (4)
21.2 % 22.5 % (1.3) % (5.8) %
____________________
(1) Exclusive of depreciation and amortization.
(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.
(4) The non-GAAP financial measure of Adjusted EBITDA margin for the pressure pumping segment is calculated by taking Adjusted EBITDA for the pressure pumping segment as a percentage of our revenues for the pressure pumping segment.
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
components like fluid ends and power ends of our pressure pumping equipment that are replaced, the cost and related accumulated depreciation are removed from the balance sheet and the net amount is recognized as loss on disposal of assets.
Interest Expense. Interest expense 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.
Liquidity and Capital Resources
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.
There can be no assurance that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Future cash flows are subject to a number of variables, and are highly dependent on the drilling, completion, and production activity by our customers, which in turn is highly dependent on oil and natural gas prices. Depending upon market conditions and other factors, we may issue equity and debt securities or take other actions necessary to fund our business or meet our future long-term liquidity requirements.
Cash and Cash Flows
The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2021 and 2020, respectively.
Year Ended December 31,
($ in thousands)
2021 2020
Net cash provided by operating activities
$ 154,714 $ 139,124
Net cash used in investing activities
$ (104,292) $ (94,217)
Net cash used in financing activities
$ (7,276) $ (125,171)
Operating Activities
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.
Investing Activities
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.
Financing Activities
Net cash used in financing activities was $7.3 million for the year ended December 31, 2021, compared to net cash used of $125.2 million for the year ended December 31, 2020. The net decrease in cash flow from financing activities during the year ended December 31, 2021 was primarily driven by no borrowings or repayments under our ABL Credit Facility in 2021 compared to repayment of borrowings of $130.0 million during the year ended December 31, 2020. During the year ended December 31, 2021, net cash outflow in connection with insurance financing was approximately $5.5 million, whereas during the year ended December 31, 2020 we received net cash inflow of $5.5 million.
Credit Facility and Other Financing Arrangements
ABL Credit Facility
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.
Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with a LIBOR floor of zero.
As of December 31, 2021, we had no borrowings outstanding under our ABL Credit Facility.
Off Balance Sheet Arrangements
We had no material off balance sheet arrangements as of December 31, 2021.
Capital Requirements, Future Sources and Use of Cash
Capital expenditures incurred were $165.2 million during the year ended December 31, 2021, as compared to $81.2 million during the year ended December 31, 2020. During the year ended December 31, 2020, we reduced our capital expenditures following the depressed demand for our pressure pumping services as a result of the COVID-19 pandemic and depressed energy market. The significant portion of our total capital expenditures were comprised of maintenance capital expenditures.
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.
We anticipate our capital expenditures will be funded by existing cash, cash flows from operations, and if needed, borrowings under our ABL Credit Facility. Our cash flows from operations will be generated from services we provide to our customers and idle fees if a customer (Pioneer) decides to idle committed fleets and we are not able to deploy the idled fleets to another customer. During times when there is a significant reduction in overall demand for our services, the idle fees could represent a material portion of our revenues and cash flows from operations.
Contractual Obligations
The following table presents our contractual obligations and other commitments as of December 31, 2021:
($ in thousands)
Period
Total 1 year or less More than I year
ABL Credit Facility (1)
$ - $ - $ -
Operating leases(2)
487 389 98
Total $ 487 $ 389 $ 98
____________________
(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.
Recent Accounting Pronouncements
Disclosure concerning recently issued accounting standards is incorporated by reference to "Note 2- Significant Accounting Policies" of our Consolidated Financial Statements contained in this Annual Report.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptable in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the years. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.
Listed below are the accounting policies that we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations.
Property and Equipment
Our property and equipment are recorded at cost, less accumulated depreciation.
Upon sale or retirement of property and equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is recognized as a gain or loss in earnings.
We primarily 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.
The estimated useful lives and salvage values of property and equipment is subject to key assumptions such as maintenance, utilization and job variation. Unanticipated future changes in these assumptions could negatively or positively impact our net income (loss). A 10% change in the useful lives of our property and equipment would have resulted in approximately $13.3 million impact on pre-tax loss during the year ended December 31, 2021. Depreciation of property and equipment is provided on the straight-line method over estimated useful lives as shown in the table below.
Land
Indefinite
Buildings and property improvements
5 - 30 years
Vehicles
1 - 5 years
Equipment
1 - 20 years
Leasehold improvements
5 - 20 years
Impairment of Long-Lived Assets
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.
Goodwill
Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized. Goodwill is not amortized. We perform an annual impairment test of goodwill as of December 31, or more frequently if circumstances indicate that impairment may exist.
There were no additions to, or disposal of, goodwill during the year ended December 31, 2021. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted active fleet revenue and cost assumptions. Our discounted cash flow analysis includes significant assumptions regarding discount rates, fleet utilization, expected profitability margin, forecasted maintenance capital expenditures, the timing of an anticipated market recovery, and the timing of expected cash flow. As such, our goodwill analysis incorporates inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecast. In March 2020, crude oil prices declined significantly, an indication that a triggering event has occurred, and as such, we recorded in our pressure pumping reportable segment, goodwill impairment expense of $9.4 million
during the year ended December 31, 2020. There was no carrying value for goodwill in our balance sheet as of December 31, 2021 because our goodwill carrying value was fully written off during 2020.
Income Taxes
Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of differences between the consolidated financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, and the results of recent operations. If we determine that we would not be able to fully realize our deferred tax assets in the future in excess of their net recorded amount, we would record a valuation allowance, which would increase our provision for income taxes. In determining our need for a valuation allowance as of December 31, 2021, we have considered and made judgments and estimates regarding estimated future taxable income. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to record additional valuation allowances for our deferred tax assets and the ultimate realization of tax assets depends on the generation of sufficient taxable income.
Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we forecast certain tax elements, such as future taxable income, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts. The final determination of our income tax liabilities involves the interpretation of local tax laws and related authorities in each jurisdiction. Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosure of Market Risks
Foreign Currency Exchange Risk
Our operations are currently conducted entirely within the U.S; therefore, we had no significant exposure to foreign currency exchange risk in 2021.
Commodity Price Risk
Our material and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our pressure pumping services such as proppants, chemicals, guar, trucking and fluid supplies. Our fuel costs consist primarily of diesel and natural gas used by our various trucks and other motorized equipment. The prices for fuel and materials in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Historically, we have generally been able to pass along a significant portion of our commodity price risk to our customers; however, we may be unable to do so in the future. We do not engage in commodity price hedging activities.
Interest Rate Risk
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.
Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk are trade receivables. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including maintaining an allowance for doubtful accounts.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
ProPetro Holding Corp. and Subsidiary
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of ProPetro Holding Corp. and Subsidiary (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of operations, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively, referred to as, the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 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.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. 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 U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Related-party transactions - Refer to Note 13 to the consolidated financial statements
Critical Audit Matter Description
The Company engages in various related party transactions, including leasing real estate, renting equipment, purchasing assets, obtaining equipment maintenance and repair services, and providing pressure pumping and related services.
We identified related-party transactions as a critical audit matter because of the number of related-party transactions and potential conflicts of interest. As a result, we believe the risk that related-party transactions were not timely identified and properly disclosed by the Company in the financial statements was elevated and required us to
exercise significant auditor judgment and an increased extent of effort when designing and performing audit procedures on related-party transactions.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures for related-party transactions included the following, among others:
•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.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2022
We have served as the Company's auditor since 2013.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
ProPetro Holding Corp. and Subsidiary
Opinion on Internal Control over Financial Reporting
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.
Basis for Opinion
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.
Definition and Limitations of Internal Control over Financial Reporting
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.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2022
PROPETRO HOLDING CORP.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2021 AND 2020
(In thousands, except share data)
2021 2020
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$ 111,918 $ 68,772
Accounts receivable - net of allowance for credit losses of $217 and $1,497, respectively
128,148 84,244
Inventories
3,949 2,729
Prepaid expenses
6,752 11,199
Other current assets
297 782
Total current assets
251,064 167,726
PROPERTY AND EQUIPMENT - Net of accumulated depreciation
808,494 880,477
OPERATING LEASE RIGHT-OF-USE ASSETS
409 709
OTHER NONCURRENT ASSETS:
Other noncurrent assets
1,269 1,827
Total other noncurrent assets
1,269 1,827
TOTAL ASSETS
$ 1,061,236 $ 1,050,739
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable
$ 152,649 $ 79,153
Accrued and other current liabilities
20,767 24,676
Operating lease liabilities
369 334
Total current liabilities
173,785 104,163
DEFERRED INCOME TAXES
61,052 75,340
NONCURRENT OPERATING LEASE LIABILITIES
97 465
Total liabilities
234,934 179,968
COMMITMENTS AND CONTINGENCIES (Note 15)
SHAREHOLDERS’ EQUITY:
Preferred stock, $0.001 par value, 30,000,000 shares authorized, none issued, respectively
- -
Common stock, $0.001 par value, 200,000,000 shares authorized, 103,437,177 and 100,912,777 shares issued, respectively
103 101
Additional paid-in capital
844,829 835,115
(Accumulated deficit) Retained earnings
(18,630) 35,555
Total shareholders’ equity
826,302 870,771
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$ 1,061,236 $ 1,050,739
See notes to consolidated financial statements. 52
PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019
(In thousands, except per share data)
2021 2020 2019
REVENUE - Service revenue
$ 874,514 $ 789,232 $ 2,052,314
COSTS AND EXPENSES:
Cost of services (exclusive of depreciation and amortization)
662,266 584,279 1,470,356
General and administrative (inclusive of stock-based compensation)
82,921 86,768 105,076
Depreciation and amortization
133,377 153,290 145,304
Impairment expense
- 38,002 3,405
Loss on disposal of assets
64,646 58,136 106,811
Total costs and expenses
943,210 920,475 1,830,952
OPERATING (LOSS) INCOME
(68,696) (131,243) 221,362
OTHER EXPENSE:
Interest expense
(614) (2,383) (7,141)
Other Income /(expense)
873 (874) (717)
Total other Income /(expense)
259 (3,257) (7,858)
(LOSS) INCOME BEFORE INCOME TAXES (68,437) (134,500) 213,504
INCOME TAX BENEFIT/ (EXPENSE)
14,252 27,480 (50,494)
NET (LOSS) INCOME
$ (54,185) $ (107,020) $ 163,010
NET (LOSS) INCOME PER COMMON SHARE:
Basic
$ (0.53) $ (1.06) $ 1.62
Diluted
$ (0.53) $ (1.06) $ 1.57
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic
102,655 100,829 100,472
Diluted
102,655 100,829 103,750
See notes to consolidated financial statements. 53
PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019
(In thousands)
Common Stock
Shares Amount Additional
Paid-In
Capital Retained Earnings (Accumulated
Deficit) Total
BALANCE - January 1, 2019 100,190 100 817,690 (20,435) 797,355
Stock-based compensation cost - - 7,776 - 7,776
Issuance of equity award-net 434 1 1,163 - 1,164
Net income - - - 163,010 163,010
BALANCE - December 31, 2019 100,624 $ 101 $ 826,629 $ 142,575 $ 969,305
Stock-based compensation cost - - 9,100 - 9,100
Issuance of equity awards-net 289 - - - -
Tax withholdings paid for net settlement of equity - - (614) - (614)
Net loss - - - (107,020) (107,020)
BALANCE - December 31, 2020 100,913 $ 101 $ 835,115 $ 35,555 $ 870,771
Stock-based compensation cost - - 11,519 - 11,519
Issuance of equity awards-net 2,524 2 4,015 - 4,017
Tax withholdings paid for net settlement of equity - - (5,820) - (5,820)
Net loss - - - (54,185) (54,185)
BALANCE - December 31, 2021 103,437 $ 103 $ 844,829 $ (18,630) $ 826,302
See notes to consolidated financial statements. 54
PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019
(In thousands)
2021 2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income $ (54,185) $ (107,020) $ 163,010
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization
133,377 153,290 145,304
Impairment expense - 38,002 3,405
Deferred income tax (benefit) expense (14,288) (27,701) 48,758
Amortization of deferred debt issuance costs
542 543 542
Stock-based compensation
11,519 9,100 7,776
Provision for credit losses 282 448 949
Loss on disposal of assets
64,646 58,136 106,812
Changes in operating assets and liabilities:
Accounts receivable
(43,742) 127,491 (10,177)
Other current assets
310 1,978 1,351
Inventories
(1,220) (293) 3,917
Prepaid expenses
4,463 (232) (4,386)
Accounts payable
51,764 (95,697) (25,242)
Accrued liabilities
1,246 (18,527) 13,088
Accrued interest
- (394) 183
Net cash provided by operating activities
154,714 139,124 455,290
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
(143,523) (100,603) (502,894)
Proceeds from sale of assets
39,231 6,386 7,595
Net cash used in investing activities
(104,292) (94,217) (495,299)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings
- - 110,000
Repayments of borrowings
- (130,000) (50,000)
Payment of finance lease obligation
- (30) (272)
Proceeds from insurance financing
- 6,821 -
Repayments of insurance financing
(5,473) (1,348) (4,547)
Proceeds from exercise of equity awards
4,017 - 1,164
Tax withholdings paid for net settlement of equity awards (5,820) (614) -
Net cash used in financing activities
(7,276) (125,171) 56,345
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 43,146 (80,264) 16,336
CASH AND CASH EQUIVALENTS - Beginning of year
68,772 149,036 132,700
CASH AND CASH EQUIVALENTS - End of year
$ 111,918 $ 68,772 $ 149,036
See notes to consolidated financial statements. 55
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND HISTORY
ProPetro Holding Corp. ("Holding"), a Texas corporation was formed on April 14, 2007, to serve as a holding company for its wholly owned subsidiary ProPetro Services, Inc. ("Services"), a Texas corporation. Services offers hydraulic fracturing, cementing and coiled tubing services to oil and gas producers, located primarily in Texas, New Mexico and Utah. Holding was converted and incorporated to a Delaware Corporation on March 8, 2017.
Unless otherwise indicated, references in these notes to consolidated financial statements to "ProPetro Holding Corp.," "the Company," "we," "our," "us" or like terms refer to ProPetro Holding Corp. and Services.
On December 31, 2018, we consummated the purchase of pressure pumping and related assets of Pioneer Natural Resources USA, Inc. ("Pioneer") and Pioneer Pumping Services, LLC (the "Pioneer Pressure Pumping Acquisition"). The pressure pumping assets acquired were used to provide integrated well completion services in the Permian Basin to Pioneer’s completion and production operations. The acquisition cost of the assets was comprised of $110.0 million of cash and 16.6 million shares of our common stock. The pressure pumping assets acquired included hydraulic fracturing pumps of 510,000 hydraulic horsepower ("HHP"), four coiled tubing units and the associated equipment maintenance facility. In connection with the acquisition, we became a long-term service provider to Pioneer under a pressure pumping services agreement (the "Pioneer Services Agreement"), providing pressure pumping and related services for a term of up to 10 years; provided, that Pioneer has the right to terminate the Pioneer Services Agreement, in whole or in part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026. Pioneer can increase the number of committed fleets prior to December 31, 2022. Pursuant to the Pioneer Services Agreement, the Company is entitled to receive compensation if Pioneer were to idle committed fleets ("idle fees"); however, we are first required to use all economically reasonable effort to deploy the idled fleets to another customer. At the present, we have eight fleets committed to Pioneer.
2. SIGNIFICANT ACCOUNTING POLICIES
A summary of the significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements are as follows:
Principles of Consolidation - The accompanying consolidated financial statements include the accounts of Holding and its wholly owned subsidiary, Services. All intercompany accounts and transactions have been eliminated in consolidation.
Basis of Presentation - The accompanying consolidated financial statements and related notes have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission ("SEC") and in conformity with accounting principles generally accepted in the United States of America ("GAAP").
Use of Estimates - Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses during the reporting period. Such estimates include, but are not limited to, allowance for credit losses, useful lives for depreciation of property and equipment, estimates of fair value of property and equipment, estimates related to fair value of reporting units for purposes of assessing goodwill (if any), estimates related to deferred tax assets and liabilities, including any related valuation allowances, and estimates of fair value of stock-based compensation. Actual results could differ from those estimates.
Revenue Recognition - The Company’s services are sold based upon contracts with customers. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer. The following is a description of the principal activities, aggregated into our one reportable segment-"Pressure Pumping" and "all other" category, from which the Company generates its revenue.
Pressure Pumping - Pressure pumping consists of downhole pumping services, which includes hydraulic fracturing (inclusive of acidizing services) and cementing.
Hydraulic fracturing is a well-stimulation technique intended to optimize hydrocarbon flow paths during the completion phase of shale wellbores. The process involves the injection of water, sand and chemicals under high pressure into shale formations. Our hydraulic fracturing contracts with our customers have one
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
performance obligation, which is the contracted total stages, satisfied over time. We recognize revenue over time using a progress output, unit-of-work performed method, which is based on the agreed fixed transaction price and actual stages completed. We believe that recognizing revenue based on actual stages completed faithfully depicts how our hydraulic fracturing services are transferred to our customers over time. In addition, certain of our hydraulic fracturing equipment is entitled to daily idle fee charges if a customer were to idle committed hydraulic fracturing equipment. The Company recognizes revenue related to idle fee charges on a daily basis as the performance obligations are met.
Acidizing, which is part of our hydraulic fracturing operating segment, involves a well-stimulation technique where acid or similar chemicals are injected under pressure into formations to form or expand fissures. Our acidizing contracts have one performance obligation, satisfied at a point-in-time, upon completion of the contracted service or sale of acid or chemical when control is transferred to the customer. Jobs for these services are typically short term in nature, with most jobs completed in less than a day. We recognize acidizing revenue at a point-in-time, upon completion of the performance obligation.
Our cementing services use pressure pumping equipment to deliver a slurry of liquid cement that is pumped down a well between the casing and the borehole. Our cementing contracts have one performance obligation, satisfied at a point-in-time, upon completion of the contracted service when control is transferred to the customer. Jobs for these services are typically short term in nature, with most jobs completed in less than a day. We recognize cementing revenue at a point-in-time, upon completion of the performance obligation.
The transaction price for each performance obligation for all our pressure pumping services is fixed per our contracts with our customers.
All Other- All other consists of coiled tubing operations, which are downhole well completion/remedial services. The performance obligation for these services has a fixed transaction price which is satisfied at a point-in-time upon completion of the service when control is transferred to the customer. Accordingly, we recognize revenue at a point-in-time, upon completion of the service and transfer of control to the customer.
Accounts Receivable - Accounts receivables are stated at the amount billed and billable to customers. At December 31, 2021 and 2020 accrued revenue (unbilled receivable) included as part of our accounts receivable was $19.4 million and $8.6 million, respectively. At December 31, 2021, the transaction price allocated to the remaining performance obligation for our partially completed hydraulic fracturing operations was $16.8 million, which is expected to be completed and recognized within one month following the current period balance sheet date, in our pressure pumping reportable segment. At December 31, 2020 the transaction price allocated to the remaining performance obligation for our then partially completed hydraulic fracturing operations was $14.7 million, which was recorded as part of our pressure pumping segment revenue for the year ended December 31, 2021.
As of December 31, 2021, the Company had $0.2 million allowance for credit losses. Our allowance for credit losses is based on the evaluation of both our historic collection experience and economic outlook for the oil and gas industry. We evaluated the historic loss experience on our accounts receivable and also considered separately customers with receivable balances that may be negatively impacted by current or future economic developments and market conditions. While the Company has not experienced significant credit losses in the past and has not yet seen material changes to the payment patterns of its customers, the Company cannot predict with any certainty the degree to which the impacts of the COVID-19 pandemic, including the potential impact of periodically adjusted borrowing base limits, level of hedged production, or unforeseen well shut-downs may affect the ability of its customers to timely pay receivables when due. Accordingly, in future periods, the Company may revise its estimates of expected credit losses.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
The table below shows a summary of allowance for credit losses during the year ended December 31, 2021:
($ in thousands)
2021 2020 2019
Balance - January 1, 2021 $ 1,497 $ 1,049 $ 100
Provision for credit losses during the period-net 282 448 949
Write-off during the period (1,562) - -
Balance - December 31, 2021 $ 217 $ 1,497 $ 1,049
Inventories - Inventories, which consists only of raw materials, are stated at lower of average cost and net realizable value.
Property and Equipment - The Company’s property and equipment are recorded at cost, less accumulated depreciation.
Depreciation - Depreciation of property and equipment is provided on the straight-line method over the following estimated useful lives:
Land
Indefinite
Buildings and property improvements
5 - 30 years
Vehicles
1 - 5 years
Equipment
1 - 20 years
Leasehold improvements
5 - 20 years
Upon sale or retirement of property and equipment, including certain major components of our pressure pumping equipment that are replaced, the cost and related accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is recognized as a gain or loss in the statement of operations. A significant portion of our loss on disposal of assets relates to replacement of major components like fluid and power ends. The Company recorded a loss on disposal of assets of $64.6 million, $58.1 million and $106.8 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Impairment of Long-Lived Assets - In accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 360, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company reviews its 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 asset group is less than the carrying amount of such asset group. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset group exceeds the fair value of the asset group. No impairment expense was recorded during the year ended December 31, 2021. Property and equipment impairment loss of $27.5 million and $1.1 million was recorded during the year ended December 31, 2020 relating to our pressure pumping and drilling assets, respectively. Property and equipment impairment loss of $1.2 million and $2.2 million was recorded during the year ended December 31, 2019 relating to our drilling and flowback asset groups, respectively. Our drilling and flowback asset groups are included in the “all other” category in our reportable segment disclosure.
The Company accounts for long-lived assets to be disposed of at the lower of their carrying amount or fair value, less cost to sell once management has committed to a plan to dispose of the assets.
Goodwill - Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized. Goodwill is not amortized. We perform an annual impairment test of goodwill as of December 31, or more frequently if circumstances indicate that impairment may exist. The determination of impairment is made by comparing the carrying amount of a reporting unit with its fair value, which is generally calculated using a combination of market and income approaches. If the fair value of the reporting unit exceeds the carrying value, no further testing is performed. If the fair value of the reporting unit is less
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
than the carrying value, we consider goodwill to be impaired, and the amount of impairment loss is estimated and recorded in the statement of operations.
In 2011, we acquired Technology Stimulation Services, LLC ("TSS") for $24.4 million. The assets acquired from TSS were recorded as $15.0 million of equipment with the excess of the purchase price over fair value of the assets recorded as goodwill of $9.4 million. The acquisition complemented our existing pressure pumping business. The transaction was accounted for using the acquisition method of accounting and, accordingly, assets and liabilities assumed were recorded at their fair values as of the acquisition date. There were no additions to goodwill during the year ended December 31, 2021. In the first quarter of 2020, we performed an interim impairment test and concluded that goodwill was fully impaired. As a result of our interim impairment test during the first quarter of 2020, we recorded goodwill impairment expense of $9.4 million during the year ended December 31, 2020, which fully wrote off our goodwill carrying value. There were no good will impairments during the year ended December 31, 2019.
Intangible Assets - Intangible assets with finite useful lives are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line basis over the asset’s estimated useful life.
Income Taxes - Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of differences between the consolidated financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, and the results of recent operations. If we determine that we would not be able to fully realize our deferred tax assets in the future, we would record a valuation allowance.
Advertising Expense - All advertising costs are expensed as incurred. For the years ended December 31, 2021, 2020 and 2019, advertising expense was $0.8 million, $0.4 million and $1.2 million, respectively.
Deferred Loan Costs - The Company capitalized certain costs in connection with obtaining its borrowings, including lender, legal, and accounting fees. These costs are being amortized over the term of the related loan using the straight-line method. Unamortized deferred loan costs associated with loans paid off or refinanced with different lenders are expensed in the period in which such an event occurs. Deferred loan costs are classified as a reduction of long-term debt or in certain instances as an asset in the consolidated balance sheet. Amortization of deferred loan costs is recorded as interest expense in the statement of operations, and during the years ended December 31, 2021, 2020 and 2019, the amount of expense recorded was $0.5 million, $0.5 million and $0.5 million, respectively.
Stock-Based Compensation - The Company recognizes the cost of stock-based awards on a straight-line basis over the requisite service period of the award, which is usually the vesting period under the fair value method. Total compensation cost is measured on the grant date using fair value estimates.
Insurance Financing - The Company annually renews its commercial insurance policies, and may choose to either directly pay the insurance premium or finance a portion of the premium. If the Company finances a portion of the premium, a prepaid insurance asset is recorded and amortized monthly over the relevant period.
Concentration of Credit Risk - The Company’s assets that are potentially subject to concentrations of credit risk are cash and cash equivalents and trade accounts receivable. Cash balances are maintained in financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institutions in which accounts are maintained and has not experienced any losses in such accounts. The receivables of the Company are with credible operators in the oil and natural gas industries. The Company performs ongoing evaluations as to the financial condition of its customers with respect to trade receivables.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently Issued Accounting Standards Adopted in 2021
In December 2019, the FASB Accounting Standards Update ("ASU") issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. ASU 2019-12 removes certain exceptions to the general principles in Topic 740 in Generally Accepted Accounting Principles. ASU 2019-12 is effective for public entities for fiscal years beginning after December 15, 2020, with early adoption permitted. Effective January 1, 2021, we adopted this guidance and the adoption did not materially affect the Company’s condensed consolidated financial statements.
Recently Issued Accounting Standards Not Yet Adopted in 2021
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform, which provides temporary optional guidance to companies impacted by the transition away from the London Interbank Offered Rate ("LIBOR"). The guidance provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. This guidance is effective upon issuance and expires on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition and this ASU on the Company’s consolidated financial statements.
3. SUPPLEMENTAL CASH FLOWS INFORMATION
($ in thousands)
Year Ended December 31,
2021 2020 2019
Supplemental cash flows disclosures
Interest paid
$ 72 $ 2,207 $ 6,433
Income taxes paid
$ 196 $ 1,786 $ 1,018
Supplemental disclosure of non-cash investing and financing activities
Capital expenditures included in accounts payable and accrued liabilities
$ 36,818 $ 14,803 $ 31,226
Non-cash purchases of property and equipment $ - $ - $ -
4. FAIR VALUE MEASUREMENTS
Fair value ("FV") is defined as the price that would be received to sell an asset or paid to transfer a liability (i.e., the "exit price") in an orderly transaction between market participants at the measurement date.
In determining fair value, the Company uses various valuation approaches and establishes a hierarchy for inputs used in measuring fair value that maximizes the use of relevant observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used, when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions about the assumptions other market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the observability of inputs as follows:
Level 1 - Valuations based on quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Valuation adjustments and block discounts are not applied to Level 1 instruments. Since valuations are based on quoted prices that are readily and regularly available in an active market, valuation of these instruments does not entail a significant degree of judgment.
Level 2 - Valuations based on one or more quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. FAIR VALUE MEASUREMENTS (Continued)
Level 3 - Valuations based on inputs that are unobservable and significant to the overall fair value measurement.
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, accrued and other current liabilities, and long-term debt (if any). The estimated fair value of our financial instruments at December 31, 2021 and 2020 approximated or equaled their carrying value as reflected in our consolidated balance sheets.
Assets Measured at Fair Value on a Nonrecurring Basis
There was no impairment of assets during the year ended December 31, 2021. During the year ended December 31, 2020, we recorded property and equipment impairment loss of approximately $28.6 million in connection with the depressed utilization of our pressure pumping and drilling assets. During the year ended December 31, 2019, we recorded property and equipment impairment loss of approximately $3.4 million in connection with our drilling and flowback assets, in our “all other” segment.
We generally apply fair value techniques to our reporting units on a nonrecurring basis associated with valuing potential impairment loss related to goodwill, if any. Our estimate of the reporting unit fair value is based on a combination of income and market approaches, Level 1 and 3, respectively, in the fair value hierarchy. The income approach involves the use of a discounted cash flow method, with the cash flow projections discounted at an appropriate discount rate. The market approach involves the use of comparable public companies’ market multiples in estimating the fair value. Significant assumptions include projected revenue growth, capital expenditures, utilization, gross margins, discount rates, terminal growth rates, and weight allocation between income and market approaches. If the reporting unit’s carrying amount exceeds its fair value, we consider goodwill impaired, and the impairment loss is calculated and recorded in the period. There were no additions to, or disposal of, goodwill during the years ended December 31, 2021, 2020 and 2019. In the first quarter of 2020, the depressed crude oil prices and crude oil storage challenges faced in the U.S. oil and gas industry triggered the Company to perform an interim goodwill impairment test, and as a result, we compared the carrying value of the goodwill in our hydraulic fracturing reporting unit with the estimated fair value. Our interim impairment test also considered other relevant factors, including market capitalization and market participants’ view of the oil and gas industry in reaching our conclusion that the carrying value of our goodwill in our pressure pumping reportable segment of $9.4 million was fully impaired during the first quarter of 2020. Accordingly, we recorded a goodwill impairment expense of $9.4 million in March 2020, resulting in a full write off of our goodwill. There were no good will impairment during the year ended December 31, 2019.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. PROPERTY AND EQUIPMENT
Property and equipment consisted of the following:
($ in thousands)
December 31,
2021 2020
Land
$ 10,551 $ 10,551
Buildings
30,045 29,312
Equipment and vehicles
1,248,464 1,242,698
Leasehold improvements
8,159 8,035
Subtotal
1,297,219 1,290,596
Less accumulated depreciation
(488,725) (410,119)
Property and equipment - net
$ 808,494 $ 880,477
During the years ended December 31, 2021 and 2020 and 2019, our depreciation expense was $133.4 million, $153.3 million and $145.3 million respectively.
6. LONG-TERM DEBT
Asset-Based Loan ("ABL") Credit Facility
Our revolving credit facility ("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 redetermined monthly. 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) $22.5 million. Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.
Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with a LIBOR floor of zero.
The loan origination costs relating to the ABL Credit Facility are classified as an asset in the balance sheet. There were no borrowings under the ABL Credit Facility as of December 31, 2021, and 2020.
7. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consisted of the following:
($ in thousands)
December 31,
2021 2020
Accrued insurance
- 6,553
Accrued payroll and related expenses
6,816 4,640
Capital expenditure, taxes and others accruals
13,951 13,483
Total
$ 20,767 $ 24,676
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. EMPLOYEE BENEFIT PLAN
The Company has a 401(k) plan, modified effective January 1, 2019, and the Company matches 100% of the employee contributions up to 6% of gross salary, up to the annual limit. The employees vest in the Company contributions to the 401(k) plan 25% per year, beginning in the employee’s first year of service, with full vesting occurring after four years of service. The employees are fully vested in their contributions when made. Effective April 1, 2022, the Company modified its 401(k) plan to allow for immediate vesting of the Company’s contributions. During the years ended December 31, 2021, 2020 and 2019, the recorded expense under the plan was $2.8 million, $2.1 million and $3.0 million, respectively.
9. REPORTABLE SEGMENT INFORMATION
The Company has three operating segments for which discrete financial information is readily available: hydraulic fracturing (inclusive of acidizing), cementing and coiled tubing. These operating segments represent how the Chief Operating Decision Maker evaluates performance and allocates resources.
In December 2021, the Company disposed of two turbine generators included in our pressure pumping reportable segment for total cash proceeds of approximately $36.0 million. The net book value of the two turbines prior to the disposal was approximately $39.5 million, resulting in loss on disposal of approximately $3.5 million. In September 2020, the Company shut down its drilling operations and disposed of all of its drilling rigs and ancillary assets for approximately $0.5 million. In March 2020, the Company shut down its flowback operating segment and subsequently disposed of the assets for approximately $1.6 million. Our drilling and flowback operations were included in our “all other” category. The shutdown of the drilling and flowback operations resulted in a reduction in the number of our current operating segments to three. The change in the number of our operating segments did not impact our reportable segment information reported for the years presented.
In accordance with FASB ASC 280-Segment Reporting, the Company has one reportable segment (pressure pumping) comprised of the hydraulic fracturing and cementing operating segments. The coiled tubing operating segment and corporate administrative expense (inclusive of our total income tax expense (benefit), other (income) and expense and interest expense) are included in the "all other" category in the tables below. Total corporate administrative expense for the years ended December 31, 2021, 2020 and 2019 was $38.5 million, $31.6 million and $113.0 million, respectively.
Our hydraulic fracturing operating segment revenue approximated 93.3%, 94.2% and 95.6% of our pressure pumping revenue for the years ended December 31, 2021, 2020 and 2019, respectively.
Inter-segment revenues are not material and are not shown separately in the table below.
The Company manages and assesses the performance of the reportable segment by its adjusted EBITDA (earnings before other income (expense), interest expense, income taxes, depreciation and amortization, stock-based compensation expense, severance and related expense, impairment expense, (gain)/loss on disposal of assets and other unusual or nonrecurring expenses or (income)).
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. REPORTABLE SEGMENT INFORMATION (Continued)
A reconciliation from segment level financial information to the consolidated statement of operations is provided in the table below (in thousands):
Pressure
Pumping
All Other
Total
Year ended and as of December 31, 2021
Service revenue
$ 857,642 $ 16,872 $ 874,514
Adjusted EBITDA
$ 181,688 $ (46,681) $ 135,007
Depreciation and amortization
$ 129,478 $ 3,899 $ 133,377
Capital expenditures
$ 162,044 $ 3,114 $ 165,158
Total assets
$ 1,023,037 $ 38,199 $ 1,061,236
Pressure
Pumping
All Other
Total
Year ended and as of December 31, 2020
Service revenue
$ 773,474 $ 15,758 $ 789,232
Adjusted EBITDA
$ 174,030 $ (32,567) $ 141,463
Depreciation and amortization
$ 148,659 $ 4,631 $ 153,290
Impairment expense
$ 36,907 $ 1,095 $ 38,002
Capital expenditures
$ 78,154 $ 3,091 $ 81,245
Total assets $ 1,009,631 $ 41,108 $ 1,050,739
Pressure
Pumping
All Other
Total
Year ended and as of December 31, 2019
Service revenue
$ 2,001,627 $ 50,687 $ 2,052,314
Adjusted EBITDA
$ 533,760 $ (14,691) $ 519,069
Depreciation and amortization
$ 139,348 $ 5,956 $ 145,304
Impairment expense $ - $ 3,405 $ 3,405
Capital expenditures
$ 387,119 $ 13,552 $ 400,671
Goodwill
$ 9,425 $ - $ 9,425
Total assets
$ 1,381,811 $ 54,300 $ 1,436,111
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. REPORTABLE SEGMENT INFORMATION (Continued)
Reconciliation of net income (loss) to adjusted EBITDA (in thousands):
Pressure
Pumping
All Other
Total
Year ended December 31, 2021
Net loss $ (12,723) $ (41,462) $ (54,185)
Depreciation and amortization
129,478 3,899 133,377
Interest expense
- 614 614
Income tax benefit - (14,252) (14,252)
Loss (gain) on disposal of assets 64,903 (257) 64,646
Stock-based compensation
- 11,519 11,519
Other income - (873) (873)
Other general and administrative expense (1)
- (6,471) (6,471)
Severance expense 30 602 632
Adjusted EBITDA
$ 181,688 $ (46,681) $ 135,007
Pressure
Pumping All Other Total
Year ended December 31, 2020
Net loss $ (68,271) $ (38,749) $ (107,020)
Depreciation and amortization
148,659 4,631 153,290
Interest expense
1 2,382 2,383
Income tax benefit - (27,480) (27,480)
Loss on disposal of assets
56,659 1,477 58,136
Impairment expense 36,907 1,095 38,002
Stock-based compensation
- 9,100 9,100
Other expense
- 874 874
Other general and administrative expense (1)
- 13,038 13,038
Retention bonus and severance expense 75 1,065 1,140
Adjusted EBITDA
$ 174,030 $ (32,567) $ 141,463
Pressure
Pumping All Other Total
Year ended December 31, 2019
Net income (loss)
$ 281,090 $ (118,080) $ 163,010
Depreciation and amortization
139,348 5,956 145,304
Interest expense
51 7,090 7,141
Income tax expense - 50,494 50,494
Loss on disposal of assets
106,178 633 106,811
Impairment expense - 3,405 3,405
Stock-based compensation
- 7,776 7,776
Other expense
- 717 717
Other general and administrative expense (1)
- 25,208 25,208
Deferred IPO bonus, retention bonus and severance expense 7,093 2,110 9,203
Adjusted EBITDA
$ 533,760 $ (14,691) $ 519,069
(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.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. REPORTABLE SEGMENT INFORMATION (Continued)
Major Customers
The Company had revenue from the following significant customers that accounted for the following percentages of the Company’s total revenue:
Year Ended December 31,
2021 2020 2019
Customer A
54.2 % 42.5 % 25.5 %
Customer B
14.6 % 20.3 % 20.9 %
Customer C
8.8 % 9.3 % 13.2 %
Customer D
4.4 % 8.6 % 9.2 %
Customer E
3.8 % 5.8 % 8.2 %
The above significant customers’ revenue that relates to pressure pumping is below:
Year Ended December 31,
2021 2020 2019
Customer A 99.6 % 99.8 % 99.7 %
Customer B 100.0 % 97.6 % 95.4 %
Customer C 99.7 % 99.9 % 99.9 %
Customer D 87.6 % 99.7 % 100.0 %
Customer E 100.0 % 85.7 % 100.0 %
10. NET (LOSS) INCOME PER SHARE
Basic net (loss) income per common share is computed by dividing the net (loss) income relevant to the common stockholders by the weighted-average number of shares outstanding during the year. Diluted net (loss) income per common share uses the same net (loss) income divided by the sum of the weighted-average number of shares of common stock outstanding during the period, plus dilutive effects of options, performance stock units and restricted stock units outstanding during the period calculated using the treasury method and the potential dilutive effects of preferred stocks (if any) calculated using the if-converted method.
(In thousands, except for per share data)
Year Ended December 31,
2021 2020 2019
Numerator (both basic and diluted)
Net (loss) income relevant to common stockholders $ (54,185) $ (107,020) $ 163,010
Denominator
Denominator for basic net (loss) income per share 102,655 100,829 100,472
Dilutive effect of stock options - - 2,929
Dilutive effect of performance stock units - - 169
Dilutive effect of restricted stock units - - 179
Denominator for diluted net (loss) income per share 102,655 100,829 103,750
Basic net (loss) income per common share $ (0.53) $ (1.06) $ 1.62
Diluted net (loss) income per common share $ (0.53) $ (1.06) $ 1.57
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. NET (LOSS) INCOME PER SHARE (Continued)
As shown in the table below, the following stock options, restricted stock units and performance stock units outstanding as of December 31, 2021, 2020 and 2019 have not been included in the calculation of diluted (loss) income per common share for the years ended December 31, 2021, 2020 and 2019 because they would be anti-dilutive to the calculation of diluted net (loss) income per common share:
(In thousands)
2021 2020 2019
Stock options 798 4,200 -
Restricted stock units 1,413 1,165 -
Performance stock units 1,586 1,019 -
Total 3,797 6,384 -
11. STOCK-BASED COMPENSATION
Stock Option Plan
In March 2013, we approved the Stock Option Plan of ProPetro Holding Corp. (the "Stock Option Plan") pursuant to which our Board of Directors may grant stock options to our consultants, directors, executives and employees. No awards have been granted under the Stock Option Plan following our Initial Public Offering ("IPO"), and no further awards will be granted under the Stock Option Plan.
2017 Incentive Award Plan
In March 2017, our shareholders approved the ProPetro Holding Corp. 2017 Incentive Award Plan (the "2017 Incentive Plan") pursuant to which our Board of Directors was authorized to grant stock options, restricted stock units ("RSUs"), performance stock units ("PSUs"), or other stock-based and cash awards to consultants, directors, executives and employees. The 2017 Incentive Plan originally authorized up to 5,800,000 shares of common stock to be issued with respect to awards granted pursuant to the plan. No awards have been granted under the 2017 Incentive Plan following approval of the 2020 Incentive Plan (as defined below), and no further awards will be granted under the 2017 Incentive Plan.
2020 Long Term Incentive Plan
In October 2020, our shareholders approved the ProPetro Holding Corp. 2020 Long Term Incentive Plan (the "2020 Incentive Plan") pursuant to which our Board of Directors may grant stock options, RSUs, PSUs, or other stock-based and cash awards to consultants, directors, executives and employees. The 2020 Incentive Plan authorizes up to 4,650,000 shares of common stock to be issued under awards granted pursuant to the plan. The 2020 Incentive Plan became effective October 22, 2020, and as of such date no further awards will be granted under the 2017 Incentive Plan.
The 2017 Incentive Plan and the 2020 Incentive Plan are herein collectively referred to as the "Incentive Plans".
Stock Options
On June 14, 2013, we granted 2,799,408 stock option awards to certain key employees, officers and directors pursuant to the Stock Option Plan that vested and became exercisable based upon the achievement of a service requirement. The options vested in 25% increments for each year of continuous service and an option became fully vested upon the optionee’s completion of the fourth year of service. The contractual term for the options awarded is 10 years. The fair value of each option award granted was estimated on the date of grant using the Black-Scholes option-pricing model.
On July 19, 2016, we granted 1,274,549 stock option awards to certain key employees, officers and directors pursuant to the Stock Option Plan which vested in five substantially equal semi-annual installments commencing in December 2016, subject to a continuing services requirement. The contractual term for the options awarded is 10 years. We fully accelerated vesting of the options in connection with our IPO. The fair value of each option award granted was estimated on the date of grant using the Black-Scholes option-pricing model.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. STOCK-BASED COMPENSATION (Continued)
On March 16, 2017, we granted 793,738 stock option awards to certain key employees, officers and directors pursuant to the 2017 Incentive Plan which are scheduled to vest in four substantially equal annual installments, subject to a continuing service requirement. The contractual term for the options awarded is 10 years. The fair value of each stock option award granted was estimated on the date of grant using the Black-Scholes option-pricing model. There were no new stock option grants during the years ended December 31, 2021, 2020 and 2019.
As of December 31, 2021, the aggregate intrinsic value for our outstanding stock options was $1.6 million, and the aggregate intrinsic value for our exercisable stock options was $1.6 million. The aggregate intrinsic value for the exercised stock options during the year ended December 31, 2021 was $19.8 million. The remaining contractual term for the outstanding and exercisable stock options as of December 31, 2021, was 4.1 years and 4.1 years, respectively.
A summary of the stock option activity during the year ended December 31, 2021 is presented below (in thousands, except for exercise price):
Number
of Shares
Weighted
Average
Exercise
Price
Outstanding at January 1, 2021 4,200 $ 4.82
Granted
- $ -
Exercised
(3,326) $ 3.42
Forfeited
- $ 0.00
Expired
(76) $ 14.00
Outstanding at December 31, 2021 798 $ 9.77
Exercisable at December 31, 2021 798 $ 9.77
Restricted Stock Units
In 2021, we granted 851,885 RSUs to employees, officers and directors pursuant to the 2020 Incentive Plan, which generally vest ratably over a three-year vesting period, in the case of awards to employees and officers, and generally vest in full after one year, in the case of awards to directors. RSUs are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient ceases to be an employee or director of the Company prior to vesting of the award. Each RSU represents the right to receive either one share of common stock or, as determined by the administrator in its sole discretion, a cash amount equal to the fair market value of one share of common stock on the day immediately preceding the settlement date. The grant date fair value of the RSUs is based on the closing share price of our common stock on the date of grant. For the years ended December 31, 2021, 2020 and 2019, the Company recognized stock compensation expense for RSUs of approximately $6.2 million, $5.1 million and $3.5 million, respectively.
As of December 31, 2021, the total unrecognized compensation expense for all RSUs was approximately $7.4 million, and is expected to be recognized over a weighted-average period of approximately 1.8 years.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. STOCK-BASED COMPENSATION (Continued)
The following table summarizes the RSUs activity during the year December 31, 2021 (in thousands, except for fair value):
Number of
Shares Weighted
Average
Grant Date
Fair Value ("FV")
Outstanding at January 1, 2021 1,165 $ 8.50
Granted 852 $ 9.69
Vested (589) $ 8.52
Forfeited (15) $ 10.27
Canceled - $ -
Outstanding at December 31, 2021 1,413 $ 9.19
Performance Stock Units
In 2021, we granted 650,774 PSUs to certain key employees and officers as new awards under the 2020 Incentive Plan. Each PSU earned represents the right to receive either one share of common stock or, as determined by the administrator in its sole discretion, a cash amount equal to the fair market value of one share of common stock or amount of cash on the day immediately preceding the settlement date. The actual number of shares of common stock that may be issued under the PSUs ranges from 0% up to a maximum of 200% of the target number of PSUs granted to the participant, based on our total shareholder return ("TSR") relative to a designated peer group, generally at the end of a three-year period. In addition to the TSR conditions, vesting of the PSUs is generally subject to the recipient’s continued employment through the end of the applicable performance period. Compensation expense is recorded ratably over the corresponding requisite service period. The grant date fair value of PSUs is determined using a Monte Carlo probability model. Grant recipients do not have any shareholder rights until performance relative to the peer group has been determined following the completion of the performance period and shares have been issued.
For the years ended December 31, 2021, 2020 and 2019 the Company recognized stock compensation expense for the PSUs of approximately $5.5 million, $1.7 million and $3.8 million, respectively.
The following table summarizes information about PSUs activity during the year ended December 31, 2021 (in thousands, except for fair value):
Period
Granted Target Shares Outstanding at January 1, 2021 Target
Shares
Granted Target Shares Vested Target
Shares
Forfeited Target Shares Outstanding at December 31, 2021 Weighted
Average
Grant Date
FV Per
Share
2018 84 - (84) - - $ 27.51
2019 126 - - - 126 $ 27.49
2020 809 - - - 809 $ 8.30
2021 - 651 - - 651 $ 14.76
Total 1,019 651 (84) - 1,586 $ 12.48
Weighted Average FV Per Share $ 12.27 $ 14.76 $ 27.51 $ - $ 12.48
The total stock compensation expense for the years ended December 31, 2021, 2020 and 2019 for all stock awards was approximately $11.5 million, $9.1 million and $7.8 million, respectively. The total unrecognized stock-based compensation expense as of December 31, 2021 was approximately $16.4 million, and is expected to be recognized over a weighted-average period of approximately 1.8 years.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. INCOME TAXES
The components of the provision for income taxes are as follows:
($ in thousands)
Year Ended December 31,
2021 2020 2019
Federal:
Current
$ (52) $ - $ -
Deferred
(15,143) (27,104) 47,090
(15,195) (27,104) 47,090
State:
Current
88 221 1,736
Deferred
855 (597) 1,668
943 (376) 3,404
Total income tax expense
$ (14,252) $ (27,480) $ 50,494
Reconciliation between the amounts determined by applying the federal statutory rate of 21% for years ended December 31, 2021, 2020 and 2019 to income tax (benefit) expense is as follows:
($ in thousands)
Year Ended December 31,
2021 2020 2019
Taxes at federal statutory rate
$ (14,372) $ (28,245) $ 44,836
State taxes, net of federal benefit
61 154 2,504
Non-deductible expenses
745 314 3,683
Stock-based compensation
(2,549) 751 (717)
Valuation allowance
825 868 -
Other
1,038 (1,322) 188
Total income tax (benefit) expense
$ (14,252) $ (27,480) $ 50,494
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. INCOME TAXES (Continued)
Deferred tax assets and liabilities are recognized for estimated future tax effects of temporary differences between the tax basis of an asset or liability and its reported amount in the consolidated financial statements. The significant items giving rise to deferred tax assets (liabilities) are as follows:
($ in thousands)
December 31,
2021 2020
Deferred Income Tax Assets
Accrued liabilities
$ 911 $ 472
Allowance for credit losses 46 316
Goodwill and other intangible assets
2,161 3,408
Stock-based compensation
3,382 4,015
Net operating losses
87,822 85,827
Other
56 56
Total deferred tax assets
94,378 94,094
Valuation allowance
(1,693) (868)
Total deferred tax assets - net
$ 92,685 $ 93,226
Deferred Income Tax Liabilities
Property and equipment
$ (152,624) $ (166,494)
Prepaid expenses
(1,113) (2,073)
Total deferred tax liabilities
$ (153,737) $ (168,567)
Net deferred tax liabilities
$ (61,052) $ (75,341)
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, the Company had approximately $408.0 million of federal NOLs some of which will begin to expire in 2035. Approximately $219.5 million of the Company’s federal NOLs relate to pre-2018 periods. As of December 31, 2021, the Company’s state net operating losses were approximately $50.1 million and will begin to expire in 2024. Utilization of net operating loss carryforwards may be limited due to past or future ownership changes. As of December 31, 2021, we determined that $1.7 million valuation allowance was necessary against our state deferred tax assets.
The Company’s U.S. federal income tax returns for the year ended December 31, 2018, and through the most recent filing remain open to examination by the Internal Revenue Service under the applicable U.S. federal statute of limitations provisions. The various states in which the Company is subject to income tax are generally open to examination for the tax years ended December 31, 2017, and through the most recent filing.
The Company records uncertain tax positions in accordance with ASC 740, Income Taxes, on the basis of a two-step process in which (1) we determine whether it is more likely than not that the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, we recognize the largest amount of tax benefit that is more than fifty percent likely to be realized upon ultimate settlement with the related tax authority. As of December 31, 2021, 2020 and 2019, no uncertain tax positions were recorded. The Company will continue to evaluate its tax positions in accordance with ASC 740 and will recognize any future effect as either a benefit or charge to income in the applicable period.
Income tax penalties and interest assessments recognized under ASC 740 are accrued as a tax expense in the period that the Company’s taxes are in an uncertain tax position. Any accrued tax penalties or interest assessments will remain until the uncertain tax position is resolved with the taxing authorities or until the applicable statute of limitations has expired.
13. RELATED-PARTY TRANSACTIONS
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. RELATED-PARTY TRANSACTIONS (Continued)
Corporate Office Building
Prior to April 2020, the Company rented its corporate office building and the associated real property from an entity, in which a former executive officer of the Company has an equity interest for approximately $0.1 million per year. In April 2020, the Company acquired the corporate office building and associated real property for approximately $1.5 million.
Operations and Maintenance Yards
The Company also rents five yards from an entity, in which certain former executive officers and a director of the Company have equity interests and total annual rent expense for each of the five yards was approximately $0.03 million, $0.03 million, $0.1 million, $0.1 million, and $0.2 million, respectively. The Company also leased its drilling yard from another entity, in which a certain former executive officer of the Company has an equity interest, for an annual lease expense of approximately $0.1 million during 2020. In November 2020, we terminated the drilling yard lease.
Equipment Rental and Other Services
The Company obtained equipment maintenance services from an entity that has a family relationship with an executive officer of the Company. During the year ended December 31, 2021 and 2020, the Company incurred approximately $0 and $1.2 million, respectively, for equipment maintenance services associated with this related party.
At December 31, 2021 and 2020, the Company had no outstanding payables or receivables to or from the above related party.
Pioneer
On December 31, 2018, we consummated the Pioneer Pressure Pumping Acquisition. In connection with the Pioneer Pressure Pumping Acquisition, Pioneer received 16.6 million shares of our common stock and approximately $110.0 million in cash.
Revenue from services provided to Pioneer (including idle fees) accounted for approximately $473.8 million, $335.4 million and $524.2 million of our total revenue during the years ended December 31, 2021, 2020 and 2019, respectively.
In connection with the Pioneer Pressure Pumping Acquisition, the Company agreed to reimburse Pioneer for a certain portion of the retention bonuses paid to former Pioneer employees that were subsequently employed by the Company. During years ended December 31, 2021, 2020 and 2019, the Company fully reimbursed Pioneer approximately $0, $2.7 million and $4.2 million respectively.
As of December 31, 2021, the total accounts receivable due from Pioneer, including estimated unbilled receivable for services (including idle fees) we provided, amounted to $62.1 million and the amount due to Pioneer was $0. As of December 31, 2020, the balance due from Pioneer for services (including idle fees) we provided amounted to approximately $41.7 million and the amount due to Pioneer was $0.
14. LEASES
On January 1, 2019, we implemented ASC 842, using the modified retrospective transition method and elected not to restate prior years. Accordingly, the effects of adopting ASC 842 were adjusted in the beginning of 2019 while prior periods are accounted for under the legacy GAAP, ASC 840. There was no cumulative effect adjustment on beginning retained earnings. We also elected other practical expedients provided by the new lease standard, the short-term lease recognition practical expedient in which leases with a term of twelve months or less will not be recognized on the balance sheet and the practical expedient to not separate lease and non-lease components for real estate class of assets. Our discount rate was based on our estimated incremental borrowing rate on a collateralized basis with similar terms and economic considerations as our lease payments at the lease commencement. Below is a description of our operating and finance leases.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. LEASES (Continued)
Operating Leases
Description of Lease
In March 2013, we entered into a ten-year real estate lease contract (the “Real Estate Lease”) with a commencement date of April 1, 2013, as part of the expansion of our equipment yard. The lease is with an entity in which a former director of the Company has a noncontrolling equity ownership interest. For the years ended December 31, 2021, 2020 and 2019, the Company made lease payments of approximately $0.4 million, $0.4 million and $0.4 million, respectively. The assets and liabilities under this contract are equally allocated between our cementing and coiled tubing segments. In addition to the contractual lease period, the contract includes an optional renewal of up to ten years, and in management’s judgment the exercise of the renewal option is not reasonably assured. The contract does not include a residual value guarantee, covenants or financial restrictions. Further, the Real Estate Lease does not contain variability in payments resulting from either an index change or rate change. Effective January 1, 2019, the remaining lease term in our present value estimate of the minimum future lease payments was approximately four years.
We accounted for our Real Estate Lease to be an operating lease. Our assumptions resulted from the existence of the right to control the use of the assets throughout the lease term. We did not account for the land separately from the building of the real estate lease because we concluded that the accounting effect was insignificant. As of December 31, 2021, the weighted average discount rate and remaining lease term was 6.7% and 1.3 years, respectively.
As of December 31, 2021, our total operating lease right-of-use asset cost was $1.2 million, and accumulated amortization was $0.8 million. As of December 31, 2020, our total operating lease right-of-use asset cost was $1.2 million, and accumulated amortization was $0.5 million. For the years ended December 31, 2021, 2020 and 2019 we recorded operating lease cost of $0.3 million, $0.3 million and $0.4 million respectively, in our statement of operations.
Finance Leases
Description of Ground Lease
In 2018, we entered into a ten-year land lease contract (the “Ground Lease”) with an exclusive option to purchase the land exercisable beginning one year from the commencement date of October 1, 2018 through the end of the contractual lease term. In March 2020, the Company exercised its option and purchased the land associated with the Ground Lease for approximately $2.5 million.
The maturity analysis of liabilities and reconciliation to undiscounted and discounted remaining future lease payments for operating lease as of December 31, 2021 are as follows:
($ in thousands) Totals
2022 $ 389
2023 98
Total undiscounted future lease payments 487
Amount representing interest (21)
Present value of future lease payments (lease obligation) $ 466
The total cash paid for amounts included in the measurement of our operating lease liability during the year ended December 31, 2021 was approximately $0.4 million. During the year ended December 31, 2020, the total cash paid for amounts included in the measurement of our operating and finance lease liabilities was approximately $0.4 million and $0.03 million, respectively. The non-cash lease obligation we recorded effective January 1, 2019, upon adopting the new lease standard, ASC 842, was $2.0 million and $3.1 million for operating and finance leases, respectively.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. LEASES (Continued)
Short-Term Leases
We elected the practical expedient, consistent with ASC 842, to exclude leases with an initial term of twelve months or less ("short-term lease") from our balance sheet and continue to record short-term leases as a period expense. For the years ended December 31, 2021 and 2020, our short-term asset lease expense was approximately $0.6 million and $1.0 million, respectively.
In April 2021, we entered into a short-term lease arrangement to lease our turbine (the “Equipment Lease”) with a commencement date of June 1, 2021 through September 30, 2021. We classified the Equipment Lease as an operating lease, and during the year ended December 31, 2021, we recognized approximately $3.0 million in lease income recorded as part of our pressure pumping segment revenue on our statements of operations.
15. COMMITMENTS AND CONTINGENCIES
Commitments
We entered into certain commitments for fixed assets, consumables and services incidental to the ordinary conduct of our business, generally for quantities required for our operations and at competitive market prices. These commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. As of December 31, 2021, there were no outstanding contractual commitments. At December 31, 2021, the total remaining commitments and other obligations for all of our short-term lease and lodging arrangements was $3.7 million.
The Company enters into purchase agreements with its sand suppliers (the "Sand Suppliers") to secure supply of sand as part of its normal course of business. The agreements with the Sand Suppliers require that the Company purchase a minimum volume of sand, based primarily on a certain percentage of our sand requirements from our customers or in certain situations based on predetermined fixed minimum volumes, otherwise certain penalties (shortfall fees) may be charged. The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the minimum volumes or a fixed price per ton of unpurchased volumes. Our agreements with Sand Suppliers expire at different times prior to December 31, 2025. During the years ended December 31, 2021, 2020 and 2019, no shortfall fee was recorded. However, one of our Sand Suppliers has filed a suit against us that includes claims related to alleged shortfall fees. The suit is in the early stages, and we are contesting the claims. While we cannot reasonably estimate the outcome of the matter at this time, in the opinion of management, the ultimate disposition of the action will not have a materially adverse effect on the Company.
One of the Sand Suppliers ("SandCo") we entered into an agreement to purchase sand ("Texas Sand") has an indirect relationship with a former executive officer of the Company, because beginning in 2018, the Texas Sand was sourced from a mine located on land owned by an entity in which the former executive officer of the Company has a 44% noncontrolling equity interest. The total sand purchased from SandCo during the three months ended March 31, 2020 (the period the former executive was associated with the Company) was approximately $5.3 million.
As of December 31, 2021 and 2020, the Company had issued letters of credit of $3.7 million and $3.7 million, respectively, under the ABL Credit Facility in connection with the Company's casualty insurance policy.
Contingent Liabilities
Legal Matters
In September 2019, a complaint, captioned Richard Logan, Individually and On Behalf of All Others Similarly Situated, Plaintiff, v. ProPetro Holding Corp., et al., (the "Logan Lawsuit"), was filed against the Company and certain of its then current and former officers and directors in the U.S. District Court for the Western District of Texas.
In July 2020, the Logan Lawsuit Lead Plaintiffs Nykredit Portefølje Administration A/S, Oklahoma Firefighters Pension and Retirement System, Oklahoma Law Enforcement Retirement System, Oklahoma Police Pension and Retirement System, and Oklahoma City Employee Retirement System, and additional named plaintiff Police and Fire Retirement System of the City of Detroit, individually and on behalf of a putative class of shareholders who purchased the Company’s common stock between March 17, 2017 and March 13, 2020, filed a
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. COMMITMENTS AND CONTINGENCIES (Continued)
third amended class action complaint in the U.S. District Court for the Western District of Texas, alleging violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule l0b-5 promulgated thereunder, and Sections 11 and 15 of the Securities Act of 1933, as amended, based on allegedly inaccurate or misleading statements, or omissions of material facts, about the Company’s business, operations and prospects against the Company, and certain of its current and former officers and directors. On September 13, 2021, the Court partially granted and partially denied motions to dismiss filed by the Company and the individual defendants. Discovery is still ongoing.
In May 2020, the U.S. District Court for the Western District of Texas consolidated two shareholder derivative lawsuits previously filed against the Company and certain of its current and former officers and directors into a single lawsuit captioned In re ProPetro Holding Corp. Derivative Litigation (the “Shareholder Derivative Lawsuit”). In August 2020, the plaintiffs in the Shareholder Derivative Lawsuit filed a consolidated complaint alleging (i) breaches of fiduciary duties, (ii) unjust enrichment and (iii) contribution. The plaintiffs did not quantify any alleged damages in its complaint but, in addition to attorneys’ fees and costs, they seek various forms of relief, including (i) damages sustained by the Company as a result of the alleged misconduct, (ii) punitive damages and (iii) equitable relief in the form of improvements to the Company’s governance and controls. On September 15, 2021, the Court granted the Company's motion to dismiss the complaint in its entirety, without prejudice.
On November 19, 2021, the Company received a demand letter from a law firm representing one of the purported shareholders of the Company that previously filed the dismissed Shareholder Derivative Lawsuit. The demand letter alleged facts and claims substantially similar to the Shareholder Derivative Lawsuit. The Board of Directors has constituted a committee to evaluate the demand letter and recommend a course of action to the Board of Directors, and the committee has retained counsel to assist with its review. The committee’s review is ongoing.
In October 2019, the Company received a letter from the SEC indicating that the SEC had opened an investigation into the Company, which followed the SEC’s issuance of a formal order of investigation, and requesting that the Company provide certain information and documents, including documents related to the Company's expanded audit committee review and related events. In November 2021, the Company entered a settlement with the SEC resolving the investigation. The Company was not required to pay any monetary penalty and has no ongoing undertakings in connection with the settlement.
We are presently unable to predict the duration, scope or result of the Logan Lawsuit, or any other related lawsuit or investigation. As of December 31, 2021, no provision was made by the Company in connection with this pending lawsuit as the final outcome cannot be reasonably estimated.
Environmental and Equipment Insurance
The Company is subject to various federal, state and local environmental laws and regulations that establish standards and requirements for protection of the environment. The Company cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Company continues to monitor the status of these laws and regulations. Currently, the Company has not been fined, cited or notified of any environmental violations that would have a material adverse effect upon its financial position, liquidity or capital resources. However, management does recognize that by the very nature of the Company's business, material costs could be incurred in the near term to maintain compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible regulation or liabilities, the unknown timing and extent of the corrective actions which may be required, the determination of the Company's liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnification.
Effective November 2021 and in connection with our equipment insurance program renewal, the Company will self-insure up to $10 million per occurrence for certain losses arising from or attributable to fire and/or explosion at the wellsites.
Regulatory Audits
In 2020, the Texas Comptroller of Public Accounts (the “Comptroller”) commenced a routine audit of the Company's motor vehicle and other related fuel taxes for the periods of July 2015 through December 2020. As of December 31, 2021, the audit is still ongoing and the final outcome cannot be reasonably estimated.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. COMMITMENTS AND CONTINGENCIES (Continued)
In January 2022, we entered into a settlement agreement with the Comptroller for a $10.7 million tax refund, net of consulting fees, in connection with certain limited sales and use tax for the audit period July 1, 2015 through December 31, 2018. The net refund will be recorded in our first quarter of 2022, the period the refund is expected to be received by the Company. During the year December 31, 2021, the net refund received by the Company from the sales and excise and use tax audit was approximately $2.1 million, which was recorded as part of other income in the statement of operations.
16. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table sets forth our unaudited quarterly results for each of the last four quarters for the years ended December 31, 2021 and 2020. This unaudited quarterly information has been prepared on the same basis as our annual audited financial statements and includes all adjustments, consisting only of normal recurring adjustments that are necessary to present fairly the financial information for the fiscal quarters presented.
(In thousands, except for per share data)
First Quarter Second Quarter Third Quarter Fourth Quarter
Revenue - Service revenue $ 161,458 $ 216,887 $ 250,099 $ 246,070
Gross profit $ 38,080 $ 54,050 $ 61,409 $ 58,709
Net income
$ (20,375) $ (8,511) $ (5,067) $ (20,232)
Net income per common share:
Basic
$ (0.20) $ (0.08) $ (0.05) $ (0.20)
Diluted
$ (0.20) $ (0.08) $ (0.05) $ (0.20)
Weighted average common shares outstanding:
Basic
101,550 102,398 103,257 103,390
Diluted
101,550 102,398 103,257 103,390
First Quarter Second Quarter Third Quarter Fourth Quarter
Revenue - Service revenue $ 395,069 $ 106,109 $ 133,710 $ 154,344
Gross profit $ 94,221 $ 37,916 $ 34,118 $ 38,698
Net income
$ (7,804) $ (25,920) $ (29,184) $ (44,112)
Net income per common share:
Basic
$ (0.08) $ (0.26) $ (0.29) $ (0.44)
Diluted
$ (0.08) $ (0.26) $ (0.29) $ (0.44)
Weighted average common shares outstanding:
Basic
100,687 100,821 100,897 100,911
Diluted
100,687 100,821 100,897 100,911

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that the information required to be disclosed by us in our reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2021.
Management’s Report on Internal Control over Financial Reporting
The management of ProPetro Holding Corp. is responsible for establishing and maintaining adequate internal control over financial reporting for the Company, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. ProPetro Holding Corp. maintains a system of internal accounting controls designed to provide reasonable assurance, at a reasonable cost, that assets are safeguarded against loss or unauthorized use and that the financial records are adequate and can be relied upon to produce financial statements in accordance with U.S. GAAP. The internal control system is augmented by written policies and procedures, an internal audit program and the selection and training of qualified personnel. This system includes policies that require adherence to ethical business standards and compliance with all applicable laws and regulations.
There are inherent limitations to the effectiveness of any control system. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Also, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company will be detected. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. The Company intends to continually improve and refine its internal controls.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our internal control over financial reporting as of December 31, 2021 based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management believes that ProPetro Holding Corp. maintained effective internal control over financial reporting as of December 31, 2021. The independent registered public accounting firm, Deloitte & Touche LLP, Houston, Texas, United States, Auditor Firm ID #34, has audited the consolidated financial statements as of and for the year ended December 31, 2021, and has also issued their report on the effectiveness of the Company’s internal control over financial reporting, included in this Annual Report under Part II, Item 8 above.
Changes in Internal Control over Financial Reporting
There were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
This information is incorporated by reference to the Company’s Proxy Statement for its 2022 Annual Meeting of Stockholders, which is expected to be filed before the end April 2022.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
This information is incorporated by reference to the Company’s Proxy Statement for its 2022 Annual Meeting of Stockholders, which is expected to be filed before the end of April 2022.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
This information is incorporated by reference to the Company’s Proxy Statement for its 2022 Annual Meeting of Stockholders, which is expected to be filed before the end of April 2022.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Party Transactions, and Director Independence.
This information is incorporated by reference to the Company’s Proxy Statement for its 2022 Annual Meeting of Stockholders, which is expected to be filed before the end of April 2022.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
This information is incorporated by reference to the Company’s Proxy Statement for its 2022 Annual Meeting of Stockholders, which is expected to be filed before the end of April 2022.
Part IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules.
(a)(1) Financial Statements
The Financial Statements in Item 8 are filed as part of this Annual Report.
(a)(2) Financial Statement Schedules
None.
(a)(3) Exhibits
The exhibits required to be filed by this Item 15(b) are set forth in the Exhibit Index included below.
(b) See Exhibit Index
(c) None
EXHIBIT INDEX
Exhibit
Number Description
2.1 Purchase and Sale Agreement, dated as of November 12, 2018, by and among Pioneer Natural Resources Pumping Services LLC, Pioneer Natural Resources USA, Inc. and ProPetro Holding Corp. (incorporated by reference herein to Exhibit 2.1 to ProPetro Holding Corp.’s Current Report on Form 8-K dated December 31, 2018).
3.1 Certificate of Incorporation of ProPetro Holding Corp., as amended March 16, 2017 (incorporated by reference herein to Exhibit 3.1 to ProPetro Holding Corp.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
3.2 Amended and Restated Bylaws of ProPetro Holding Corp. (incorporated by reference herein to Exhibit 3.2 to ProPetro Holding Corp.’s Current Report on Form 8-K dated June 19, 2019).
3.3 Certificate of Designations of Series B Junior Participating Preferred Stock of ProPetro Holding Corp. (incorporated by reference herein to Exhibit 3.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated April 14, 2020).
4.1 Specimen Stock Certificate (incorporated by reference herein to Exhibit 4.1 to ProPetro Holding Corp.’s Registration Statement on Form S-1, dated February 23, 2017 (Registration No. 333-215940).
4.2 Investor Rights Agreement, dated as of December 31, 2018, by and between Pioneer Natural Resources Pumping Services LLC and ProPetro Holding Corp. (incorporated by reference herein to Exhibit 4.1 to ProPetro Holding Corp.’s Current Report on Form 8-K dated December 31, 2018).
4.3 Registration Rights Agreement, dated as of December 31, 2018, by and between Pioneer Natural Resources Pumping Services LLC and ProPetro Holding Corp. (incorporated by reference herein to Exhibit 4.2 to ProPetro Holding Corp.’s Current Report on Form 8-K dated December 31, 2018).
4.4 Description of Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference herein to Exhibit 4.4 to ProPetro Holding Corp.'s Annual Report on Form 10-K for the year ended December 31, 2019).
4.5 Rights Agreement, dated as of April 14, 2020, by and between ProPetro Holding Corp. and American Stock Transfer & Trust Company, LLC (incorporated by reference herein to Exhibit 4.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated April 14, 2020).
10.1 Credit Agreement, dated as of March 22, 2017 by and among ProPetro Holding Corp., ProPetro Services, Inc., Barclays Bank PLC, as the Agent, the Collateral Agent, a Letter of Credit Issuer and the Swingline Lender, and each of the Lenders from time to time party thereto (incorporated by reference herein to Exhibit 10.2 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated March 28, 2017).
10.2# Stock Option Plan of ProPetro Holding Corp., dated March 4, 2013 (incorporated by reference herein to Exhibit 10.6 to ProPetro Holding Corp.’s Registration Statement on Form S-1, dated February 7, 2017 (Registration No. 333-215940)).
10.3# First Amendment to the Stock Option Plan of ProPetro Holding Corp., dated June 14, 2013 (incorporated by reference herein to Exhibit 10.7 to ProPetro Holding Corp.’s Registration Statement on Form S-1, dated February 7, 2017 (Registration No. 333-215940)).
10.4# Second Amendment to the Stock Option Plan of ProPetro Holding Corp., dated December 2, 2016 (incorporated by reference herein to Exhibit 10.8 to ProPetro Holding Corp.’s Registration Statement on Form S-1, dated February 7, 2017 (Registration No. 333-215940)).
10.5# Non-Qualified Stock Option Agreement, dated June 14, 2013, by and between ProPetro Holding Corp. and Spencer D. Armour, III (incorporated by reference herein to Exhibit 10.12 to ProPetro Holding Corp.’s Registration Statement on Form S-1, dated February 7, 2017 (Registration No. 333-215940)).
10.6# Non-Qualified Stock Option Agreement, dated July 19, 2016, by and between ProPetro Holding Corp. and Spencer D. Armour, III (incorporated by reference herein to Exhibit 10.16 to ProPetro Holding Corp.’s Registration Statement on Form S-1, dated February 7, 2017 (Registration No. 333-215940)).
10.7# Form of ProPetro Holding Corp. 2017 Incentive Award Plan (incorporated by reference herein to Exhibit 10.18 to ProPetro Holding Corp.’s Registration Statement on Form S-1/A, dated March 7, 2017 (Registration No. 333-215940)).
10.8# ProPetro Holding Corp. 2020 Long Term Incentive Plan (incorporated by reference herein to Exhibit 10.3 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated October 26, 2020).
10.9# Form of ProPetro Holding Corp. Senior Executive Incentive Bonus Plan (incorporated by reference herein to Exhibit 10.19 to ProPetro Holding Corp.’s Registration Statement on Form S-1/A, dated February 23, 2017 (Registration No. 333-215940)).
10.10# Form of ProPetro Holding Corp. 2017 Incentive Award Plan Stock Option Grant Notice and Stock Option Agreement (incorporated by reference herein to Exhibit 10.22 to ProPetro Holding Corp.’s Registration Statement on Form S-1/A, dated February 23, 2017 (Registration No. 333-215940)).
10.11# Form of ProPetro Holding Corp. Amendment to Non-Qualified Stock Option Agreement (incorporated by reference herein to Exhibit 10.23 to ProPetro Holding Corp.’s Registration Statement on Form S-1/A, dated February 23, 2017 (Registration No. 333-215940)).
10.12# 2017 Form of ProPetro Holding Corp. 2017 Incentive Award Plan Performance Restricted Stock Unit Grant Notice and Performance Restricted Stock Unit Agreement (incorporated by reference herein to Exhibit 10.1 to ProPetro Holding Corp.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).
10.13# 2017 Form of ProPetro Holding Corp. 2017 Incentive Award Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Employees) (incorporated by reference herein to Exhibit 10.2 to ProPetro Holding Corp.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).
10.14# 2019 Form of ProPetro Holding Corp. 2017 Incentive Award Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Employees) (incorporated by reference herein to Exhibit 10.26 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2019).
10.15# 2019 Form of ProPetro Holding Corp. 2017 Incentive Award Plan Performance Restricted Stock Unit Grant Notice and Performance Restricted Stock Unit Agreement (incorporated by reference herein to Exhibit 10.27 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2019).
10.16# 2019 Form of ProPetro Holding Corp. 2017 Incentive Award Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference herein to Exhibit 10.28 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2019).
10.17# 2020 Form of ProPetro Holding Corp. 2020 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors). (incorporated by reference herein to Exhibit 10.29 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2020).
10.18# Letter Agreement, dated October 4, 2019, by and between Phillip Gobe and ProPetro Holding Corp. (incorporated by reference herein to Exhibit 10.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated October 9, 2019).
10.19# ProPetro Services, Inc. Executive Severance Plan (incorporated by reference herein to Exhibit 10.3 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated March 16, 2020).
10.20# Form of Participation Agreement pursuant to the ProPetro Services, Inc. Executive Severance Plan (incorporated by reference herein to Exhibit 10.4 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated March 16, 2020).
10.21# Participation Agreement pursuant to the ProPetro Services, Inc. Executive Severance Plan, between Phillip A. Gobe and ProPetro Services, Inc., dated March 13, 2020 (incorporated by reference herein to Exhibit 10.5 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated March 16, 2020).
10.22# Amended and Restated ProPetro Holding Corp. Executive Incentive Bonus Plan (incorporated by reference herein to Exhibit 10.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated February 18, 2020).
10.23# Amendment No. 1 to Credit Agreement, dated as of February 22, 2018 by and among ProPetro Holding Corp., ProPetro Services, Inc., the Incremental Lenders therein, the Required Lenders and Barclays Bank PLC, as Administrative Agent for the Lenders (incorporated by reference herein to Exhibit 10.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated February 27, 2018).
10.24# Amendment No. 2 to Credit Agreement, dated as of December 19, 2018, by and among ProPetro Holding Corp., ProPetro Services, Inc., the Incremental Lenders therein, the Required Lenders and Barclays Bank PLC, as Administrative Agent for the Lenders (incorporated by reference herein to Exhibit 10.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated December 21, 2018).
10.25# Pressure Pumping Services Agreement dated December 31, 2018, between Pioneer Natural Resources USA, Inc. and ProPetro Services, Inc. (incorporated by reference herein to Exhibit 10.31 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2018).
10.26# Form of Indemnification Agreement for Pioneer Designated Directors (incorporated by reference herein to Exhibit 10.32 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2018).
10.27# Form of Indemnification Agreement for Officers and Directors of ProPetro Holding Corp. (incorporated by reference herein to Exhibit 10.33 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2018).
10.28# ProPetro Services, Inc. Amended and Restated Executive Severance Plan (incorporated by reference herein to Exhibit 10.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated April 10, 2020).
10.29# ProPetro Services, Inc. Second Amended and Restated Executive Severance Plan (incorporated by reference herein to Exhibit 10.4 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated October 26, 2020).
10.30# Form of Participation Agreement pursuant to the ProPetro Services, Inc. Second Amended and Restated Executive Severance Plan (incorporated by reference herein to Exhibit 10.5 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated October 26, 2020).
10.31 Waiver to Credit Agreement, dated as of March 17, 2020 by and among ProPetro Holding Corp., ProPetro Services, Inc., Barclays Bank PLC, as the Agent, the Collateral Agent, a Letter of Credit Issuer and the Swingline Lender, and each of the Lenders from time to time party thereto (incorporated by reference herein to Exhibit 10.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated March 23, 2020).
10.32 Waiver to Credit Agreement, dated as of June 22, 2020 by and among ProPetro Holding Corp., ProPetro Services, Inc., Barclays Bank PLC, as the Agent, the Collateral Agent, a Letter of Credit Issuer and the Swingline Lender, and each of the Lenders from time to time party thereto (incorporated by reference herein to Exhibit 10.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated June 23, 2020).
10.33# Participation Agreement pursuant to the ProPetro Services, Inc. Executive Severance Plan, dated March 16, 2020, by and between Newton W. Wilson III and ProPetro Services, Inc. (incorporated by reference herein to Exhibit 10.51 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2019).
10.34# Amended and Restated ProPetro Holding Corp. Non-Employee Director Compensation Policy (incorporated by reference herein to Exhibit 10.53 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2019).
10.35# 2020 Form of ProPetro Holding Corp. 2017 Incentive Award Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Employees) (incorporated by reference herein to Exhibit 10.54 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2019).
10.36# 2020 Form of ProPetro Holding Corp. 2017 Incentive Award Plan Performance Restricted Stock Unit Grant Notice and Performance Restricted Stock Unit Agreement (Employees) (incorporated by reference herein to Exhibit 10.55 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2019).
10.37# 2021 Form of ProPetro Holding Corp. 2020 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Employees) (incorporated by reference herein to Exhibit 10.1 to ProPetro Holding Corp.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021).
10.38# 2021 Form of ProPetro Holding Corp. 2020 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (incorporated by reference herein to Exhibit 10.2 to ProPetro Holding Corp.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021).
10.39# Participation Agreement pursuant to the ProPetro Services, Inc. Second Amended and Restated Executive Severance Plan, dated July 28, 2021, by and between Newton W. Wilson III and ProPetro Services, Inc (incorporated by reference herein to Exhibit 10.2 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated July 27, 2021).
21.1(a) List of Subsidiaries of ProPetro Holding Corp.
23.1(a) Consent of Independent Registered Public Accounting Firm.
31.1(a) Certification of Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2(a) Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1(b) Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2(b) Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS(a) XBRL Instance Document
101.SCH(a) XBRL Taxonomy Extension Schema Document
101.CAL(a) XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB(a) XBRL Taxonomy Extension Label Linkbase Document
101.PRE(a) XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF(a) XBRL Taxonomy Extension Definition Linkbase Document
104(a) Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
(a) Filed herewith.
(b) Furnished herewith.
# Compensatory plan, contract or arrangement.