EDGAR 10-K Filing

Company CIK: 1680247
Filing Year: 2025
Filename: 1680247_10-K_2025_0001680247-25-000030.json

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ITEM 1. BUSINESS
Item 1. Business.
Our Company
We are a leading integrated energy service company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline, and other complementary energy and power generation services to leading upstream oil and gas companies engaged in the 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 and natural gas producing areas in the United States, and we believe we are one of the leading providers of energy services in the region.
In the fourth quarter of 2024, we formed a new subsidiary, ProPetro Energy Solutions, LLC, doing business as PROPWRSM, to provide power generation services to oil and gas producers and for general industrial projects and data centers. PROPWR has ordered equipment, but has not yet begun revenue-generating activities.
On November 1, 2024, we sold our cementing business located in Vernal, Utah, to a business owned by a former employee as part of a strategic repositioning. We received a promissory note for $13.0 million as consideration. The note receivable is secured by substantially all assets of the divested operations and the former employee’s ownership interests in and distributions from the business. The note receivable is to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025, to December 31, 2029. We recorded a gain on disposal of $8.2 million related to the sale of the business. The former employee was part of our cementing operations until November 1, 2024, and is no longer affiliated with the Company.
On May 31, 2024, we consummated the acquisition of all of the outstanding equity interests in Aqua Prop, LLC (“AquaPropSM”), which provides wet sand solutions for hydraulic fracturing at well sites (the “AquaProp Acquisition”). The consideration for the AquaProp Acquisition included $13.7 million of cash paid to the seller, $3.7 million of deferred cash consideration payable to the seller by May 31, 2025, the payoff of $7.2 million of the seller’s outstanding debt, the payment of $0.3 million of certain transaction costs and estimated contingent consideration of $10.9 million. As a result of the AquaProp Acquisition, we expanded our business to include wet sand services.
On December 1, 2023, we consummated the purchase of the assets and operations of Par Five Energy Services LLC (“Par Five”), which provides cementing services in the Delaware Basin in exchange for $25.4 million of cash, including deferred cash consideration of $3.1 million which is payable to Par Five or its beneficiary on June 1, 2025, with interest at 4.0% per annum. (the “Par Five Acquisition”). The Par Five Acquisition complemented our existing cementing business and enabled us to serve both the Midland and Delaware sub-basins of the Permian Basin.
On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC (the “Silvertip Acquisition”), which provides wireline perforation and ancillary services in the Permian Basin in exchange for 10.1 million shares of our common stock valued at $106.7 million, $30.0 million of cash, the payoff of $7.2 million of assumed debt, and the payment of certain other closing and transaction costs. Collectively, the AquaProp Acquisition, the Par Five Acquisition and the Silvertip Acquisition have positioned the Company as a more integrated and diversified completions-focused energy service provider. See Note 4. Business Acquisitions in the financial statements for additional disclosures.
Effective September 1, 2022, we disposed of our coiled tubing assets to STEP Energy Services Ltd. (“STEP”) and shut down our coiled tubing operations. We received approximately $2.8 million in cash and 2.6 million common shares of STEP, valued at $11.8 million, as consideration. Upon the sale of our coiled tubing assets, we recorded a loss on sale of $13.8 million.
Our competitors include many large and small energy service companies, including Halliburton Company, Liberty Energy Inc., Patterson-UTI Energy Inc., ProFrac Holding Corp., Solaris Energy Infrastructure, Inc., RPC, Inc., and a number of private and locally-oriented businesses. The markets in which we operate are highly competitive. To be successful, an energy service 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, technology, 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 new technologies and 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, lack of large-scale deployment of certain new technology such as electric-powered equipment, and the pricing for our services and expected return on invested capital. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our operational efficiencies, productivity, equipment quality and technology, reliability, ability to manage multifaceted logistics challenges, commitment to safety and the ability of our people to handle the most complex Permian Basin well completions and power generation challenges.
We believe that our substantial market presence in the Permian Basin positions us well to capitalize on drilling, and completion activity and power demand in the region. Our operational focus has primarily been in the Permian Basin's Midland sub-basin, where our customers have operated. However, we have increased our operations in the Delaware sub-basin and are well-positioned to support further increases in our activity in this area in response to demand from our customers. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.
Additionally, we believe the significant natural gas production in the Permian Basin will become a natural market for power-intensive businesses including data centers and other industrial businesses seeking alternative solutions for reliable and available electricity requirements which are not dependent on grid or public utility limitations.
We primarily provide hydraulic fracturing, wireline, and cementing completion services to E&P companies in the Permian Basin. Our equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region's increasingly high-intensity well completions (including simultaneous hydraulic fracturing (“Simul-Frac”), which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. We also launched a new power generation business, PROPWR, that will provide power generation services to oil and gas producers and other industrial companies and data centers.
Commodity Price and Other Economic Conditions
The oil and gas industry has traditionally been volatile and is characterized by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, war and political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control.
The geopolitical and macroeconomic consequences of military action in the Middle East, the Russian invasion of Ukraine, including the associated sanctions, and the adverse impacts of the COVID-19 pandemic have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing. As the global response to the COVID-19 pandemic began to wane, the demand and prices for crude oil increased from the lows experienced in 2020, with the West Texas Intermediate (“WTI”) average crude oil price reaching approximately $94 per barrel in 2022, the highest average price in the prior ten years. However, the WTI average crude oil price declined to approximately $78 per barrel in 2023 and approximately $76 per barrel in 2024. We believe that the volatility of crude oil prices in recent years has been partly driven by declines in crude oil supplies, concerns over sanctions resulting from Russia's invasion of Ukraine, concerns over a potential disruption of Middle Eastern oil supplies resulting from the conflict in the Middle East, slower crude oil production growth due to the lack of reinvestment in the oil and gas industry in the last three years, the extension of OPEC+ production cuts of approximately 3.9 million barrels per day originally announced in 2023 and concerns of a potential global recession resulting from high inflation and interest rates.
With the significant increase in global crude oil prices from 2021, including the WTI crude oil price, there was a significant increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of 2022, according to the Baker Hughes Company (“Baker Hughes”). Following the increase in rig count and the WTI crude oil price, the energy service industry has experienced increased demand for its completion services, and improved pricing. However, the Permian Basin rig count experienced a 13% decrease to 309 at the end of 2023 and further decreased to 304 at the end of 2024 which resulted in a reduction in the demand for completion services and pressure on pricing of our services.
Sustained levels of high inflation likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including interest rates, labor costs and equipment. We cannot predict any future trends in the rate of inflation and crude oil prices. A significant increase in or continued high levels of inflation, to the extent we are unable to timely pass-through the cost increases to our
customers, further declines in crude oil prices, or potential changes in U.S trade policy, including the imposition of tariffs and the resulting consequences, would negatively impact our business, financial condition and results of operations. See Part II, Item 1A. “Risk Factors-We may be adversely affected by the effects of inflation.”
Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including upstream and energy service companies. As a result, we are working with our customers and equipment manufacturers to transition our equipment into a lower emissions profile. Currently, a number of lower emission solutions for pumping equipment, including Tier IV DGB dual-fuel, FORCE® electric, direct drive gas turbine and other technologies have been developed, and we expect additional lower emission solutions will be developed in the future. We are continually evaluating these technologies and other investment and acquisition opportunities that would support our existing and new customer relationships. The transition to lower emissions equipment is quickly evolving and will be capital intensive. Over time, we may be required to convert substantially all of our conventional Tier II equipment to lower emissions equipment. We have transitioned our hydraulic fracturing available equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022, 60% in 2023 and 70% in 2024, and expect to increase to approximately 75% by the end of the first quarter of 2025. To the extent any of our customers have certain expectations or requirements with respect to emissions reductions from their contractors, if we are unable to continue quickly transitioning to lower emissions equipment, the demand for our services could be adversely impacted.
If the Permian Basin rig count and market conditions improve, including improved pricing for our services and labor availability, and we are able to meet our customers' lower emissions equipment demands, we believe our operational and financial results will also improve. If the rig count or market conditions do not improve or decline in the future, and we are unable to increase our pricing or pass-through future cost increases for our customers, there could be a material adverse impact on our business, results of operations and cash flows.
Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to the holiday season, inclement winter weather and the exhaustion of our customers' annual budgets. As a result, we typically experience declines in our operating and financial results in November and December, even in a stable commodity price and operations environment.
Our Services
We have historically conducted our business through four operating segments: hydraulic fracturing, wireline, cementing and coiled tubing. Prior to the fourth quarter of fiscal year 2023, our operating segments met the aggregation criteria and were aggregated into the “Completion Services” reportable segment and our coiled tubing operations (which were divested in September 2022) were shown in the “All Other” category. Effective in the fourth quarter of fiscal year 2023, we revised our segment reporting as we determined that our operating segments no longer met the criteria to be aggregated. In the fourth quarter of fiscal year 2024, we formed PROPWR to provide power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. This new subsidiary has ordered equipment, but it has not yet begun any revenue-generating activities. Our hydraulic fracturing, wireline and cementing operating segments meet the criteria of a reportable segment. Our divested coiled tubing and our newly formed power generation services segments do not meet the reportable segment criteria and are included within the “All Other” category. Additionally, our corporate administrative activities do not involve business activities from which it may earn revenues and its results are not regularly reviewed by the Company’s Chief Operating Decision Maker (the “CODM”) when making key operating and resource decisions. As a result, corporate administrative expenses have been included under “Reconciling Items.” For additional financial information on our reportable segment presentation, please see reportable segment information in Part II - Item 8, “Financial Statements and Supplementary Data.”
Hydraulic Fracturing
We provide hydraulic fracturing services to E&P companies in the Permian Basin. These services are intended to optimize hydrocarbon flow paths during the completion phase of horizontal shale wellbores. We have significant expertise in multi-stage fracturing of horizontal oil-producing wells in unconventional geological formations. Our total available hydraulic horsepower (“HHP”) at December 31, 2024, was 1,556,500 HHP, which was comprised of 450,000 HHP of our Tier IV DGB dual-fuel equipment, 294,000 HHP of FORCE® electric-powered equipment and 812,500 HHP of conventional Tier II equipment. Our hydraulic fracturing fleets range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsite. Our equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region’s increasingly high-intensity well completions, including (“Simul-Frac”), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. With the industry transition to
lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in 2021 and 2022, we committed to additional conversions of some of our Tier II equipment to Tier IV DGB, and to purchase new Tier IV DGB dual-fuel equipment. As such, we entered into conversion and purchase agreements with our equipment manufacturers and received all of the converted and new Tier IV DGB dual-fuel equipment by the end of 2023, representing 450,000 HHP of our Tier IV DGB dual-fuel equipment as of December 31, 2024. In 2022, we entered into three-year electric fleet leases for four FORCE® electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet (the “Electric Fleet Leases”) and in June 2024, we entered into an additional three-year lease for a fifth FORCE® electric-powered hydraulic fracturing fleet with 72,000 HHP. As of December 31, 2024, we have received 294,000 HHP of FORCE® electric-powered equipment representing four fleets and a portion of the fifth fleet. We currently expect to receive the remaining equipment associated with the fifth fleet in the first half of 2025.
The hydraulic fracturing process consists of pumping 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.” Our hydraulic fracturing units consist primarily of high pressure hydraulic pumps, diesel or dual gas engines, gas turbine generators, transmissions and various hoses, valves, tanks and other supporting equipment like blenders, irons, hoses and data vans. We also own and operate a fleet of trucks, trailers and other equipment that provide onsite storage and handling of wet sand used in the completion phase of shale wellbores.
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.
Wireline
We provide wireline and ancillary services on new oil well completions in the Permian Basin. Wireline utilizes equipment with a drum of wireline to deploy perforating guns in the well to perforate the casing, cement, and formation. Once the well is perforated, it is ready to be fractured. Pumpdown utilizes pressure pumping equipment to pump water into the well to deploy or push the perforating guns attached to the wireline through the lateral section of a well.
We own and operate a fleet of mobile wireline units and other auxiliary equipment to perform well completion services. We also refer to our wireline units, pressure control equipment, other equipment and vehicles necessary to perform a job as a "spread" and the personnel assigned to the spread as a "crew." On average, one wireline spread consists of a wireline tractor truck with a large cab functioning as a mobile office where the engineer controls the wireline spooled drum along with associated pressure control iron and equipment, trailers and vehicles. We currently have 26 wireline units.
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. We currently have 29 cementing units.
Power Generation Services
In December 2024, we formed PROPWR to provide power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. This subsidiary has ordered equipment, but has not yet begun revenue-generating activities.
Our Customers
Our customers consist primarily of oil and natural gas producers in North America. Our top five customers accounted for approximately 58.8%, 63.2% and 84.0% of our revenue, for the years ended December 31, 2024, 2023, and 2022, respectively. For the year ended December 31, 2024, XTO Energy Inc. (“XTO”), a wholly owned subsidiary of Exxon Mobil Corporation (“ExxonMobil”), Permian Resources and EOG Resources accounted for 19.7%, 14.9%, and 10.6%, respectively, of total revenue. No other customer accounted for more than 10% of our total revenue for the year ended December 31, 2024. There have been many recent mergers and acquisitions in the oil and gas industry. In May 2024, Pioneer Natural Resources USA, Inc. (“Pioneer”) merged with and into a wholly owned subsidiary of Exxon Mobil. We currently provide pressure pumping, wireline and other services to ExxonMobil and previously provided such services to Pioneer. Mergers and acquisitions involving our customers could negatively impact our future business with them or positively impact our business by providing us access to potential new customers.
On April 22, 2024, we entered into a sub-agreement for hydraulic fracturing services with XTO, pursuant to which we agreed to provide hydraulic fracturing, wireline and pumpdown services with two committed FORCE® electric-powered hydraulic fracturing fleets with the option to add a third FORCE® fleet (also with wireline and pumpdown services) for a period of three years or for contracted hours, whichever occurs last, with respect to each fleet, subject to certain termination and release rights.
Competition
The markets in which we operate are highly competitive. To be successful, an energy service company must provide services and equipment that meet the specific needs of oil and natural gas E&P companies at competitive prices. Competitive factors impacting sales of our services are price, reputation, technical expertise, emissions profile, service and equipment design 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 energy service industry because of the capital requirements. 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 portfolio and 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 energy service companies, including the largest integrated energy service companies. Our major competitors include Halliburton Company, Liberty Energy Inc., Patterson-UTI Energy Inc., ProFrac Holding Corp., Solaris Energy Infrastructure, Inc., RPC, 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 and financial results.
Operating Risks and Insurance
Our operations are subject to hazards inherent in the energy service 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 energy service 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 operations, coverage would be available under our pollution legal liability policy for any surface or subsurface environmental cleanup 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 and wireline services.
We maintain directors and officers insurance; however, our insurance coverage is subject to certain exclusions (including, for example, any required United States Securities and Exchange Commission (“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 all 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. 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 E&P wastes could increase our costs to manage and dispose of such wastes.
Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and analogous state laws generally impose liability without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Liability for the costs of removing or remediating previously disposed wastes or contamination, damages to natural resources, the costs of conducting certain health studies, amongst other things, is strict and joint and several. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state laws. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such hazardous substances have been released.
NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials (“NORM”) associated with oil and gas deposits and, accordingly, may result in the generation of wastes and other materials containing NORM. NORM exhibiting levels of radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements.
Water Discharges. The Clean Water Act, Safe Drinking Water Act, Oil Pollution Act and analogous state laws and regulations impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Also, spill prevention, control and countermeasure plan requirements require appropriate containment berms and similar structures to help prevent the contamination of regulated waters.
Air Emissions. The Clean Air Act (“CAA”) and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other emissions control requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants from specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These and other laws and regulations may increase the costs of compliance for some facilities where we operate. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects.
Climate Change. In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recently passed laws such as the IRA 2022 advance numerous climate-related objectives. Additionally, following the U.S. Supreme Court finding that greenhouse gas (“GHG”) emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of certain pollutants from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the Department of Transportation (“DOT”), implementing GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, the EPA has recently finalized rules covering the standards of performance for methane and volatile organic compounds emissions for oil and gas facilities, including leak detection, monitoring and repair, and a “super-
emitter” response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties, triggering certain investigation and repair requirements. These requirements were finalized in 2023, but are currently subject to legal challenge. At this time, it remains uncertain as to whether the current administration will repeal or modify this rule and the timing with respect to the same.
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. 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. However, in January 2025, the current president signed an Executive Order once again withdrawing the United States from the Paris Agreement and from any other commitments made under the United Nations Framework Convention on Climate Change. The full impact of these recent developments is uncertain at this time. For more information, see our risk factors titled “Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide” and “The IRA 2022 could accelerate the transition to a low carbon economy and could impose new costs on our customers’ operations.”
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, for example, in January 2024 the government announced a temporary pause on pending decisions on liquefied natural gas exports to certain countries. However, upon taking office, the current president signed an Executive Order resuming the processing of permit applications for such projects. 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.
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 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.
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), has, since May 2024, been listed as endangered under the ESA. To the extent any protections are implemented for this or any other species, it could cause us or our customers to incur additional costs or become subject to operating restrictions or operating bans in the affected areas.
Regulation of Hydraulic Fracturing and Related Activities. Our hydraulic fracturing operations are a significant component of our business. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. Although several of these rulemakings have been rescinded, modified or subjected to legal challenges, new or more stringent regulations may be promulgated by the current government. For example, in March 2024, the Bureau of Land Management (“BLM”) finalized a rule that requires operators to limit flaring from well sites on federal lands, and allows the delay or denial of permits if BLM finds that an operator’s methane waste minimization plan is insufficient. The rule was challenged by various states in the District Court for the District of North Dakota, and, in September 2024, that court ordered
that the rule cannot be enforced within the plaintiff states pending the outcome of the litigation. Although the rule is currently being implemented in areas not covered by the order, the future of the rule is uncertain. The previous administration also called for revisions and restrictions to the leasing and permitting programs for oil and gas development on federal lands and, for a time, suspended federal oil and gas leasing activities. The Department of the Interior (“DOI”) issued a report recommending various changes to the federal leasing program, though many such changes would require congressional action. In July 2023, the BLM finalized a rule to update the fiscal terms of federal oil and gas leases, which increases fees, rents, royalties, and bonding requirements. The rule also adds new criteria for BLM to consider when determining whether to lease nominated land, including the presence of important habitats or wetlands, the presence of historical properties or sacred sites, and recreational use of the land. Any regulations that restrict, ban or effectively ban such operations may adversely impact demand for our products and services. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have previously been proposed in Congress. Several states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.
Federal and state governments have also investigated whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for wastewater disposal wells that impose permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission’s well completion seismicity guidelines for operators in the SCOOP and STACK require hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division has previously issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. The Texas Railroad Commission (“TRRC”) has adopted similar rules including the indefinite suspension of all deep oil and gas produced water injection wells in certain areas covered by the TRRC’s seismic response program.
Increased regulation of hydraulic fracturing and related activities could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and record keeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services. For more information on each of these items, see our risk factor titled “Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”
OSHA Matters. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.
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, 2024, we employed approximately 1,900 people, and none of our employees are represented by a union. All of our employees work for or support our hydraulic fracturing, wireline, cementing and power generation services operating segments. We believe that we have good relations with our employees. We believe that our employees are a key component of our ability to attract and retain customers as a result of their operational excellence in the field.
Some examples of significant programs and initiatives that support our objective of attracting, developing and retaining our diverse and inclusive workforce include:
•Opportunity and Engagement. We are an equal opportunity employer and prohibit discrimination against any employee and applicant on the basis of any legally protected characteristic. We believe that in order to attract and retain talent with the skill sets and expertise that can help to maximize our operational efficiencies across all levels in
the Company, it is in our best interest to create a culture that is inclusive. We conducted our second annual employee engagement survey in 2024. The results show improvement in our overall employee engagement score over the 2023 survey and above industry benchmarks. The survey focuses on engagement, manager effectiveness, training and tools to ensure that employees are well equipped to do their jobs effectively and workplace culture. Attracting the right people to ProPetro remains top priority. Some examples of this effort to recruit and develop our team and culture include:
◦a commitment to conducting business in a manner that respects all human rights in compliance within the requirements of applicable laws;
◦a commitment within our business operations to promoting and encouraging respect for human rights and fundamental freedoms for all without distinctions of any kind, such as race, color, sex, language, religion, political or other opinions;
◦working with personnel, business partners and other parties directly linked to our operations that share our commitment to these same legal compliance principles;
◦maintaining employment policies reflecting our commitments, including our code of conduct, our equal employment opportunity employer policy, and our anti-harassment and anti-discrimination policy; and
◦providing an anonymous Ethics and Compliance hotline that is promoted internally and accessible from our intranet and website to make it possible for grievances regarding health and safety to be addressed early and remediated directly, in confidence and without fear of retaliation.
•Training and Safety. We offer in-depth, role-appropriate safety training upon hiring and as part of the continuous development of our employees. The safety of our employees, our customers, and the communities in which we operate is paramount. We track and evaluate safety incidents at wellsites and offices, and if an accident does occur, we aim to take actions to mitigate similar incidents from reoccurring in the future. The Company seeks to incentivize employees to focus on conducting operations in accordance with our strict safety standards and encourages employees to immediately report any breach of safety protocol. Ten percent of our executive officers’ annual target bonuses under the 2024 annual incentive program were based upon the Company’s achievement of certain safety goals, including a target total recordable incident rate.
•Professional Development. In 2024, the Company continued its focus on leadership development, targeting leadership positions including frontline supervisors and above. Internal facilitators were trained and certified to deliver content to drive program efficiency and better associate the topics and importance of the training to the business. The Company also transitioned the Human Resources Information System (HRIS) from PayCom to Workday to gain greater talent related functionality and efficiency in the areas of performance management, succession planning, learning and development and compensation planning. Responsibility for Human Capital Management (HCM) in Workday was designed to ensure the direct supervisor working closest with the employee is at the center of the conversation driving engagement, providing feedback, rewarding performance and supporting development.
•Compensation, Health, Wellness and Benefits. Our employee benefit offerings are designed to meet the varied and evolving needs of our entire 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.
In 2024, as part of our 401(k) plan, we continued to focus on financial wellness education and group and individual consultations for employees as well as encouraging participation in the program. The program opportunities included many crucial topics ranging from budgeting and debt management to understanding plan options and investment strategy. Concerning health benefits, in 2024 we added additional services focused on emotional and mental health, as well as certain preventative health services related to the early detection of concerns including breast cancer, diabetes and cardiovascular disease.
We also strive to give back to the areas in which we conduct business operations, and in which our employees live and work. Our employees give generously and receive up to eight hours per year of paid time off to participate in community service. Our employee-led P.U.M.P. Committee also organizes or sponsors events in which employees can choose to participate in addition to our paid community service time benefit.
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 Exchange Act, are made available free of charge on our internet website at www.propetroservices.com, as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the SEC. The SEC maintains an internet site that contains our reports, proxy and information statements and our other SEC filings. The address of that website is www.sec.gov. Please note that information contained on our website, whether currently posted or posted in the future, is not a part of this Annual Report or the documents incorporated by reference in this Annual Report.
Board of Directors and Executive Officers
Set forth below are the names, age and business experience of the Board of Directors of the company as of February 20, 2025.
Phillip A. Gobe, 72, began serving as our Chairman of the Board in July of 2019 and as Executive Chairman in October 2019. Mr. Gobe was appointed as our Chief Executive Officer on March 13, 2020 and served in that role until August 31, 2021, at which point he was re-appointed as Executive Chairman. Mr. Gobe stepped down as Executive Chairman on March 31, 2022, and continues serving the Company as Chairman of the Board. Mr. Gobe has served as a director of Pioneer since July 2014. Mr. Gobe previously served as Chairman of the Board for Pantheon Resources PLC until his June 2023 retirement. He also previously served as a director of Scientific Drilling International and Pioneer Southwest Energy Partners L.P. Mr. Gobe joined Energy Partners, Ltd as Chief Operating Officer in December 2004 and became president in May 2005, and served in those capacities until his retirement in September 2007. Mr. Gobe also served as a director of Energy Partners, Ltd. from November 2005 until May 2008. Prior to that, Mr. Gobe served as Chief Operating Officer for Nuevo Energy Company from February 2001 until its acquisition by Plains Exploration & Production Company in May 2004. Prior to that time, he held numerous operations and human resources positions with Vastar Resources, Inc. and Atlantic Richfield Company (“ARCO”) and its subsidiaries. Mr. Gobe has a Bachelors of Arts degree from the University of Texas and a Master of Business Administration degree from the University of Louisiana in Lafayette. Mr. Gobe’s extensive experience in the energy industry, including service as a director to public corporations in the industry, makes him well suited to serve as Chairman of the Board.
Samuel D. Sledge, 38, has served as our Chief Executive Officer and as a member of our Board since August 31, 2021. Mr. Sledge previously served as the Company’s President from April 2021 to August 2021, and prior to that, he served as Chief Strategy and Administrative Officer beginning in March 2020. Mr. Sledge has significant experience with ProPetro having joined the Company in 2011. Mr. Sledge has served in various capacities throughout his tenure such as a Frac Technical Specialist and Technical Operations Manager where his duties included quality control, planning and logistics, and the development of the engineering program. Mr. Sledge has also served as ProPetro’s Vice President of Finance, Corporate Development, and Investor Relations where his responsibilities included financial planning and analysis, strategic initiatives, and investor relations. Mr. Sledge received a Bachelor of Business Administration and a Masters of Business Administration from Baylor University. We believe Mr. Sledge’s experience in the energy industry and his significant experience in management roles at the Company make him well suited to serve as a director.
Spencer D. Armour III, 71, has served as a member of our Board since February 2013. Mr. Armour has over 30 years of executive and entrepreneurial experience in the energy services industry. Mr. Armour served as President of PT Petroleum LLC in Midland, Texas from 2011 to 2018. He was the Vice President of Corporate Development for Basic Energy Services, Inc. from 2007 to 2008, which acquired Sledge Drilling Corp., a company Mr. Armour co-founded and served as Chief Executive Officer from 2005 to 2006. From 1998 through 2005, he served as Executive Vice President of Patterson-UTI Energy, Inc., which acquired Lone Star Mud, Inc., a company Mr. Armour founded and served as President from 1986 to 1997. Mr. Armour also served on the board of Patterson-UTI Energy, Inc. from 1999 to 2001. He currently serves on the boards of Viper Energy, Inc. and CES Energy Solutions Corp and is a partner at Geneses Investments. Mr. Armour received a B.S. in Economics from the University of Houston in 1977 and served on the University of Houston System Board of Regents from 2011 until 2018. We believe that Mr. Armour’s extensive experience in the energy services industry and his deep knowledge of industry dynamics within the Permian Basin make him well suited to serve as a director.
Mark S. Berg, 66, has served as a member of our Board since 2019. Mr. Berg is a senior energy industry executive with extensive commercial and operational experience, including leadership of strategic planning, business development, land, water management, completion and well services, environmental, sustainability, legal, government relations and communications. During his 20-year career with Pioneer Natural Resources (“Pioneer”), then an NYSE-listed independent oil and gas exploration and production company, first as Executive Vice President & General Counsel from 2005 to 2014 and then as Executive Vice President, Corporate Operations from 2014 until its merger with ExxonMobil in 2024, he played a key role in transforming the company into a major U.S. shale resource developer. He led the negotiating team for the $65 billion merger
with ExxonMobil as well as multiple multibillion-dollar mergers, global divestitures, and cross-border joint ventures. Prior to joining Pioneer, Mr. Berg served from 2002 to 2004 as Senior Vice President, General Counsel & Secretary of Hanover Compressor Company, then an NYSE-listed company specializing in natural gas compression and processing, where he instituted disciplined internal controls, resolved an SEC investigation, and settled securities class action litigation. From 1997 to 2002 he served as Executive Vice President & General Counsel of American General Corporation, a Fortune 200 diversified financial services company, and oversaw its $27 billion merger with American International Group (“AIG”). Mr. Berg began his career with the Houston based law firm Vinson & Elkins L.L.P. and served as a partner from 1990 through 1997, focused on mergers, acquisitions and international project development. From 2018 to 2020, he served on the board of directors of HighPoint Resources, an exploration and production company then listed on the NYSE. Effective March 2025, Mr. Berg has been appointed to serve on the boards of Oncor Electric Delivery Holdings Company LLC and Oncor Electric Delivery Company LLC, a regulated electricity transmission and distribution company. Mr. Berg also serves as the founding Vice Chairman of the Permian Strategic Partnership, a coalition of Permian Basin energy companies and higher education institutions focused on supporting public education, healthcare, road safety and workforce development in the Permian Basin region.
Anthony J. Best, 75, has served as a member of our Board since January 2018 and was elected to serve as Lead Independent Director in October 2019. Mr. Best has over 40 years of experience in the energy industry. Mr. Best retired as the Chairman of the board of Newpark Resources in May 2023. He was previously a director with Quantum Energy Partners’ (“Quantum”) portfolio companies, ExL Petroleum and Middle Fork Energy Partners, and also served as Senior Advisor for Quantum. Prior to joining Quantum, Mr. Best served in various roles with SM Energy Company, an oil and gas exploration company, commencing in 2006 as its President and Chief Operating Officer, and as its Chief Executive Officer from February 2007 through January 2015. From 2003 to 2005, Mr. Best served as President and Chief Executive Officer of Pure Resources, Inc., a Unocal development and exploration company. From 2000 to 2003, Mr. Best served as an independent consultant offering leadership and oil and gas consultation to energy companies and volunteer organizations, and from 1979 through 2000, Mr. Best served in various roles of increasing responsibility at ARCO, culminating in the position of President, ARCO Latin America. Mr. Best holds a Master of Science in Engineering Management degree from the University of Alaska and a Bachelor of Science degree in Mechanical Engineering from Texas A&M University. Prior to beginning his business career, Mr. Best served five years as an engineering officer in the United States Air Force. We believe that Mr. Best’s experience in significant management roles with companies operating in the Permian Basin and his broad experience in the energy industry make him well suited to serve as a director.
G. Larry Lawrence, 73, was appointed to our Board in December 2020. Mr. Lawrence previously served as Audit Committee Chair of Legacy Reserves, LP’s Board of Directors, a role he held from 2006 to 2019. From January 2021 until June 2021, Mr. Lawrence served as the interim Chief Financial Officer of Natural Gas Services Group, a natural gas compression equipment provider, where he previously served as Chief Financial Officer for nine years. Prior to Natural Gas Services Group, Mr. Lawrence served as Chief Financial Officer for Lynx Operating Co. Inc., an oil and gas exploration company, for three years and as Chief Financial Officer for Pure Resources, Inc., an oil and gas E&P company, for two years. He has also held finance and management consulting positions for Parson Group, ARCO and Crescent Consulting. Mr. Lawrence earned his bachelor’s degree with an accounting major from Dillard University in New Orleans. We believe that Mr. Lawrence’s broad experience in the energy industry, including his service as a director and executive officer with various companies, makes him well suited to serve as a director.
Jack B. Moore, 71, has served as a member of our Board since March 2017. Mr. Moore most recently served as President and Chief Executive Officer of Cameron International Corporation (“Cameron”), an oil and gas industry equipment manufacturer and provider, from April 2008 to October 2015 and served as Chairman of the Board of Cameron from May 2011 until it was acquired by Schlumberger in April 2016. Prior to his employment with Cameron, Mr. Moore held various management positions at Baker Hughes Incorporated, where he was employed for 23 years. Mr. Moore currently serves on the Board of Directors of Occidental Petroleum Corporation, KBR Inc., and the University of Houston System Board of Regents. Mr. Moore previously served on the board of the American Petroleum Institute, the National Ocean Industries Association, Rowan Companies plc, and the Petroleum Equipment Suppliers Association. Mr. Moore received a Bachelor of Business Administration from the University of Houston and attended the Advanced Management Program at Harvard Business School. We believe that Mr. Moore’s wealth of experience in the oilfield service sector, including service as a director and executive officer to various public corporations in the sector, makes him well suited to serve as a director.
Mary P. Ricciardello, 69, has served as a member of our Board since January 2023. Ms. Ricciardello currently serves as a director, Audit Committee member and Corporate Governance, Nominating and Sustainability Committee member at Eagle Materials Inc. Ms. Ricciardello previously served as a director at Devon Energy from 2008 to 2021, Noble Corporation from 2003 to 2020, Enlink Midstream from 2014 to 2018, Midstates Petroleum from 2010 to 2013 and U.S. Concrete from 2003 to
2010. Beginning in 1982, Ms. Ricciardello enjoyed a distinguished, two-decade career at Reliant Energy Inc. (“Reliant”) and its predecessor, Houston Lighting & Power Company, an electricity generation and retail services company, where she held several roles of increasing responsibility in the financial services and treasury functions. In 1996, Ms. Ricciardello was appointed as Reliant’s Vice President and Comptroller and she served as its Senior Vice President and Chief Accounting Officer from 1999 until her retirement in 2002. Ms. Ricciardello earned a Bachelor of Science degree in Business Administration from the University of South Dakota and an MBA from the University of Houston. She is also a Texas licensed Certified Public Accountant and earned a CERT Certificate in Cybersecurity from Carnegie Mellon University. We believe that Ms. Ricciardello is well suited to serve as a director based on her accounting and financial expertise and public company board and committee experience.
Michele Vion, 65, was appointed to our Board in February 2020. Ms. Vion previously served as Vice President, Human Resources at HighPoint Resources Corporation, a successor to the Bill Barrett Corporation, an oil and gas E&P company, from August 2010 to September 2019. Ms. Vion was previously employed at Level 3 Communications, Inc., an international communications company, starting in 2006 and ultimately as Group Vice President of Human Resources up to January 2010. Ms. Vion also previously served as Vice President of Human Resources for Sun Microsystems, Inc., a computer networking company, for seven years. She also previously held senior human resource and client account management positions at Prudential Financial, Inc., an insurance and investment management company and JP Morgan, a global financial services firm. Prior to joining JP Morgan, Ms. Vion served in an accounting position as a Regional Controller for the Eastern Region at Sony Corporation of America. Ms. Vion previously served as Compensation Committee Chair and as a member of the Audit Committee of Boingo Wireless, Inc.’s Board of Directors, roles she held from 2018 until Boingo’s acquisition by Digital Colony Management, LLC in June 2021. Ms. Vion also served on the board and as Chair of the Compensation Committee and as member of the Audit Committee and Nominating and Corporate Governance Committee of Callidus Software Inc., a publicly-traded, cloud-based software company, from 2005 to 2016. Ms. Vion holds a Bachelor of Arts in East Asian Studies and Economics from Wesleyan University, has attended Stanford University’s Director’s College, and participated in the Financial Times’ Director Exchange. We believe that Ms. Vion is well suited to serve as a director based on her executive leadership experience in human resources and accounting and public company board and committee experience.
Alex V. Volkov, 52, has served as a member of our Board since May 2024. Mr. Volkov is currently Vice President - Commercial & Integration, for ExxonMobil Upstream Unconventional business. Alex joined ExxonMobil in 1997 in Houston, Texas. During his early tenure with the company he has held diverse assignments in the areas of marketing, business development, supply chain logistics, and business strategy development. From 2014 to 2016, Alex was based in Moscow, Russia where he served as Vice President of Exxon Neftegas Limited responsible for ExxonMobil commercial activities in Russia, including natural gas sales and marketing of Sakhalin-1 gas resources. Alex moved to the United Kingdom in 2016 and he was appointed Vice President, International Gas, ExxonMobil Gas & Power Marketing and Chairman, ExxonMobil Gas Marketing Europe in 2018. In this capacity, he was responsible for ExxonMobil’s natural gas marketing and trading activities in Europe, Russia, Caspian, Malaysia, Thailand, and Australia. In 2019 Alex moved to Houston and was named Vice President, Global LNG Marketing. In this role, he had global responsibility for ExxonMobil’s Liquefied Natural Gas (LNG) portfolio and marketing of LNG for ExxonMobil’s projects and joint ventures. Between 2021 and 2023 Alex served first as Vice President, Commercial & Power and then as Vice President, Strategy and Business Development which included Upstream Acquisitions & Divestment team that was responsible for evaluation and negotiation of ExxonMobil / Pioneer merger announced in October 2023 and after the announcement he served as Transition Executive overseeing the integration of two companies . He assumed his current position in July of 2024. Alex graduated from the University of Nizhni Novgorod, Russia in 1994 and he also holds an MBA from the University of Alabama.
Set forth below are the name, age, position and description of the business experience of our executive officers (other than those who are also Directors and included above) as of February 20, 2025.
David S. Schorlemer, 57, began serving as a Special Advisor to the Chief Financial Officer on October 12, 2020 until his appointment as Chief Financial Officer on October 23, 2020. Mr. Schorlemer has two decades of experience in senior level positions in public and private companies and has focused on building integrated business systems and support organizations. He most recently served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary of Basic Energy Services, Inc., a Fort Worth, Texas based oilfield services company, from September 2018 until joining the Company. Prior to that, he served as the Chief Financial Officer of Gulf Island Fabrication, Inc. from January 2017 to August 2018. His work history also includes serving as Chief Financial Officer for three oilfield services companies: GR Energy Services Management, LP from January 2016 to December 2016, Stallion Oilfield Holdings, Inc., September 2004 to December 2015 and Q Services, Inc. from July 1997 until its merger with Key Energy Services, Inc. in July 2002. He also held the role of vice president, marketing and strategic planning for Key Energy Services, Inc. from July 2002 to September 2004. Prior to entering the energy services industry, Mr. Schorlemer was a technology consultant and project manager with Accenture’s Technology Practice
where he worked on various domestic and international projects with Fortune 500 Companies in industries including: telecommunications, transportation, automotive and manufacturing and oil and gas. Mr. Schorlemer earned his Bachelor of Business Administration degree in finance from The University of Texas, and his Master of Business Administration from Texas A&M University.
Adam Muñoz, 42, has served as our President and Chief Operating Officer since August 2021, and prior to that, he served as Chief Operating Officer since January 2021 and served as Senior Vice President of Operations since March 2020. Mr. Muñoz joined the Company in 2010 to initiate ProPetro’s Permian pressure pumping operation. Prior to joining ProPetro, Mr. Muñoz held sales and operations roles at Frac Tech Services and Weatherford International. Since joining ProPetro, Mr. Muñoz has served as the Director of Business Development and Technical Services where he was responsible for overseeing the growth of the hydraulic fracturing operations as well as managing the department’s day-to-day technical services. Mr. Muñoz has most recently served as the Vice President of Frac Services where his duties included leading the hydraulic fracturing division through specific efforts to increase operational efficiencies and maximize financial productivity. Mr. Muñoz received a Bachelor of Business Marketing from The University of Texas at the Permian Basin.
John J. “Jody” Mitchell, 42, has served as our General Counsel and Corporate Secretary of the Company since January 2023. Prior to his appointment as General Counsel, Mr. Mitchell served as the Company’s Vice President and Deputy General Counsel since April 2021. Before joining the Company, Mr. Mitchell served in various roles at Concho Resources Inc., a hydrocarbon exploration company acquired by ConocoPhillips in 2021 (“Concho”), from 2014 to 2021, including Director of Marketing and Midstream and, prior to that, Associate General Counsel. Before joining Concho, Mr. Mitchell served as counsel supporting the upstream and midstream businesses at Petrohawk Energy Corporation (“Petrohawk”) and at BHP Billiton following BHP Billiton’s acquisition of Petrohawk. Mr. Mitchell began his career as an associate at Locke Lord Bissell & Liddell LLP, where he concentrated on oil, gas and energy litigation and construction litigation. Mr. Mitchell holds a Bachelor of Arts from the University of Texas and a Juris Doctor from the University of Houston Law Center.
Shelby K. Fietz, 43, has served as our Chief Commercial Officer of the Company since November 2023. Mr. Fietz joined ProPetro in 2012, and prior to his appointment as Chief Commercial Officer, Mr. Fietz served as the Company’s Vice President of Commercial, leading the business development, sales, supply chain, and marketing functions. He also previously held the position of Vice President of Business Development, Sales and Marketing, while also leading our supply chain organization. Prior to his appointment as an officer, Mr. Fietz held roles of increasing responsibility within ProPetro in both operations and business development. Mr. Fietz also serves in a leadership capacity with the Permian Basin Chapter of the Energy Workforce and Technology Council. Mr. Fietz holds a Bachelor of Science from Angelo State University.
Celina M. Davila, 44, has served as our Chief Accounting Officer since November 2023. Prior to her appointment as Chief Accounting Officer, Ms. Davila served as the Company’s Director of Accounting and Corporate Controller since August 2022 and as Corporate Controller since October 2019. Ms. Davila joined the Company in January 2019 as Hydraulic Fracturing Controller. Prior to joining the Company, Ms. Davila served in various roles at Pioneer, a leading independent natural resources company, from 2012 to 2018, including Accounting Manager and, prior to that, Accounting Supervisor. Ms. Davila began her career as a Senior Auditor at Johnson, Miller, and Co. Ms. Davila is a Certified Public Accountant and holds a Bachelor of Arts in Accounting and a Master in Business Administration degree from Texas Tech University.

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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 E&P activity within the United States and in the Permian Basin, and a decline in prices for oil and natural gas may cause fluctuation in operating results or otherwise have an adverse effect on our revenue, cash flows, profitability and growth.
Demand for most of our services depends substantially on the level of capital expenditures in the Permian Basin by companies in the oil and natural gas industry. As a result, our operations are dependent on the levels of capital spending and activity in oil and gas exploration, development and production. Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Prolonged low oil and gas prices would generally depress the level of oil and natural gas exploration, development, production, and well completion activity and would result in a corresponding decline in the demand for the completion services that we provide. Historically, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil price per barrel was approximately $76, $78 and $94 for the years ended December 31, 2024, 2023, and 2022, respectively. In 2023, the volatility and overall decline in oil and natural gas prices caused a reduction in our customers’ spending and associated drilling and completion activities, which has had and may continue to have an adverse effect on our revenue and cash flows, if the WTI oil price remains highly volatile or declines in the future.
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 actions by the members of OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;
•the domestic and foreign supply of, and demand for, oil and natural gas;
•the level of prices, and expectations about future prices, of oil and natural gas;
•the level of global oil and natural gas E&P;
•the cost of exploring for, developing, producing and delivering oil and natural gas;
•the supply of and demand for drilling and hydraulic fracturing and wireline equipment, including the supply and demand for lower emissions hydraulic fracturing and wireline equipment;
•cost increases and supply chain constraints related to our services;
•the expected decline in rates of current production;
•the price and quantity of foreign imports;
•political and economic conditions in oil and natural gas producing countries and regions, including the United States, the Middle East, Africa, South America and Russia;
•the actions taken by the United States and other countries on climate change or to transition away from fossil fuels;
•the severity and duration of world health events and related economic repercussions;
•speculative trading in crude oil and natural gas derivative contracts;
•the level of consumer product demand;
•the discovery rates of new oil and natural gas reserves;
•contractions in the credit market;
•the strength or weakness of the U.S. dollar;
•available pipeline and other transportation capacity;
•the levels of oil and natural gas storage;
•weather conditions and other natural disasters;
•domestic and foreign tax policy;
•domestic and foreign governmental approvals and regulatory requirements and conditions, including tighter emissions standards in the energy industry and proposed tariffs;
•the result of the U.S presidential election;
•the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;
•political or civil unrest in the United States or elsewhere, including the Russia-Ukraine war and the conflict in the Israel-Gaza region and related instability in the Middle East, including from Houthi rebels in Yemen, and tensions with Iran;
•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. In 2022, Russia launched a large-scale invasion of Ukraine, leading to armed hostilities and imposition of sanctions on Russian economic trades. Since October 2023, an ongoing conflict between Israel and Palestinian militants in the Israel-Gaza region has led to armed hostilities. These events, which have impacted economic activity and disrupted global supply chain dynamics, 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 E&P 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, a decline in oil and gas prices, combined with adverse changes in the capital and credit markets, could cause many E&P companies to significantly reduce their 2020 and 2021 capital budgets and drilling activity. This could result in a significant decline in demand for energy services and could adversely impact the prices energy service 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.
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, 2024, 2023 and 2022, approximately 98.5%, 98.1% and 98.3%, respectively, of our revenues were attributable to our operations in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in the Permian Basin caused by significant governmental regulation, processing or transportation capacity constraints, market limitations, curtailment of production or interruption of the processing or transportation of oil and natural gas produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our operations, we could experience any of the same conditions at the same time, resulting in a relatively greater impact on our revenue than they might have on other companies that have more geographically diverse operations.
The IRA 2022 could accelerate the transition to a low carbon economy and could impose new costs on our customers’ operations.
The IRA 2022, signed into law in August 2022, provides for hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. If not modified, repealed or revoked by the current administration, these incentives could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for oil and gas and consequently adversely affect the business of our customers, thereby reducing demand for our services. In addition, the IRA 2022 imposes the first ever federal fee on the emission of GHG through a methane emissions charge. The IRA 2022 amends the federal CAA to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the offshore and onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge began in calendar year 2024 at $900 per ton of methane, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. We cannot predict whether how or when the current administration might take action to revise or repeal the methane emissions charge. Additionally, Congress may take actions to repeal or revise the IRA 2022, including with respect to the methane emissions charge, which timing or outcome similarly cannot be predicted. To the extent that the methane emissions charge is implemented as originally promulgated, it could increase our customers’ operating costs and adversely affect their businesses, thereby reducing demand for our services.
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 E&P 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.
New technology may cause us to become less competitive.
The energy service industry is subject to the introduction of new drilling and completion techniques and services using new technologies including artificial intelligence, some of which may be subject to patent or other intellectual property protections. As competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage. The transition to lower emissions equipment is capital intensive and could require us to convert all our conventional Tier II equipment to lower emissions equipment. If we are unable to quickly transition to lower emissions equipment, the demand for our services could be adversely impacted. For example, many E&P companies, including our customers, are transitioning to a lower emissions operating environment and may require us to invest in equipment with lower emissions profiles. Further, we may face competitive pressure to develop, implement or acquire and deploy certain technology improvements at a substantial cost, such as our FORCE® electric-powered hydraulic fracturing fleets deployed in 2023, or the cost of implementing or purchasing a technology like FORCE® may be substantially higher than anticipated, and we may not be able to successfully implement the technologies we may purchase. In 2024, we recorded a property and equipment impairment charge of $188.6 million on our conventional Tier II diesel-only hydraulic fracturing pumping units and associated conventional assets, (the "Tier II Units") because we determined that the marketability of our Tier II Units had declined due to decreasing customer demand for and related pricing pressures on such equipment, among other factors. In 2022, we recorded a property and equipment impairment charge of $57.5 million on our DuraStim® electric-powered equipment because they did
not meet our expectations. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and develop and implement new products on a timely basis or at an acceptable cost. We cannot be certain that we will be able to develop and implement new technologies or products on a timely basis or at an acceptable cost. Limits on our ability to develop, effectively use and implement new and emerging technologies could have a material adverse effect on our business, financial condition, prospects or results of operations.
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 energy service industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures. Our total capital expenditures incurred were approximately $133.4 million, $310.0 million and $365.3 million during the years ended December 31, 2024, 2023, and 2022. 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 (as defined below) was $164.1 million as of December 31, 2024. 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 (including the Russia-Ukraine war and conflicts in the Middle East, including tensions with Iran), public health crises, interest rates, inflation, the availability and cost of credit in the United States, foreign financial markets and potential changes in U.S trade policy, including the imposition of tariffs and the resulting consequences 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. In addition, there is currently significant uncertainty about the future relationship between the United States and various other countries, including changes arising as a result of the current presidential administration, with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations. 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 adversely affect our financial condition.
Our business is capital intensive and 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, research and development efforts, potential strategic acquisitions or other general corporate purposes;
•placing us at a competitive disadvantage relative to competitors that have less debt; and
• our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.
Furthermore, interest rates on future indebtedness could be higher than current levels, causing our financing costs to increase accordingly. 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.
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, has a borrowing base of the sum of 85.0% to 90.0% of eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the borrowing base), in each case, depending on the credit ratings of our accounts receivable counterparties, less customary reserves (the “Borrowing Base”). Changes to our operational activity levels or customer concentration levels have an impact on our total eligible accounts receivable, which could result in significant changes to our borrowing base and therefore our availability under our ABL Credit Facility. If our customer activity declines in the future, our borrowing base could decline. If our borrowing base is reduced below the amount of our outstanding borrowings, we will be required to repay the excess borrowings immediately on demand by the lenders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our ABL Credit Facility or any new indebtedness could have similar or greater restrictions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Credit Facility and Other Financing Arrangements.”
We may record losses or impairment charges related to goodwill and long-lived assets including intangible 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 2024, we recorded property and equipment impairment charges of $188.6 million in connection with our Tier II Units and $23.6 million in connection with the goodwill in our wireline operating segment. In 2022, we recorded property and equipment impairment charges of $57.5 million in connection with our DuraStim® electric powered hydraulic fracturing equipment. If oil and natural gas prices trade at depressed price levels, and our equipment remains idle or under-utilized, the estimated fair value of such equipment may decline, which will result in additional impairment expense in the future.
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, cleanup responsibilities, regulatory investigations and penalties or other damage resulting in curtailment or suspension of our operations or the loss of customers. For example, in January 2025, we experienced an accident at a customer site that resulted in one fatality and injured two others, which temporarily halted operations and is subject to routine investigation by OSHA. 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 wellsites that do not have qualified fire suppression measures. 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 cleanup costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the "occurrence" to our insurance company within the time frame required under our insurance policy. In addition, these policies do not provide coverage for all liabilities, and the insurance coverage may not be adequate to cover claims that may arise, or we may not be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
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, including the Russia-Ukraine war and conflicts in the Middle East, 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 us 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 frequency and magnitude of cybersecurity attacks is increasing and attackers have become more sophisticated. Cybersecurity attacks are similarly evolving and include without limitation use of malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. We may be unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not identifiable until deployed. We may also be unable to investigate or remediate incidents as attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence.
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 (if any) for protecting against cyber security risks, including cyberattacks, may not be sufficient and may not protect against or cover all of the losses (including potential reputational loss) 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 utilize technologies, controls and procedures, as well as internal staff and external service providers to protect our systems and data, to identify and remediate vulnerabilities and to monitor and respond to threats. However, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. No security measure is infallible. If we or the third parties with whom we interact were to experience a successful attack, the potential consequences to our business, workforce and the communities in which we operate could be significant, including financial losses, regulatory fines, loss of business, an inability to settle transactions or maintain operations, litigation costs, remediation costs, disruptions related to investigation, and significant damage to our reputation.
We may grow through acquisitions and/or internal expansions, and our failure to properly plan and manage such growth may adversely affect our performance.
We have completed and may in the future pursue, asset acquisitions or acquisitions of businesses. We have internally expanded and may in the future expand into new lines of business. Any acquisition of assets or businesses, or expansion into new lines of business 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, property and equipment or intangible assets 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. For example, in 2024, we acquired the assets and operations of AquaProp, and we are in the process of fully integrating all parts of the acquired business into our operations. In late 2024, we also started a new line of business to provide power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. This new line of business has not begun any revenue-generating activities yet.
We must plan and manage any acquisitions and expansions effectively to achieve revenue growth and maintain profitability in our evolving market. Any failure to manage acquisitions and expansions 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.
We may be adversely affected by the effects of inflation.
The U.S. inflation rate steadily increased in 2021 and 2022 before decreasing to a moderate level in 2023 through 2024. Inflation in wages, materials, parts, equipment and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure, particularly if we are unable to achieve commensurate increases in the prices we charge our customers for our products and services. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor, weakening exchange rates and other similar effects. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates in 2023 followed by decreases in 2024, and the U.S. Federal Reserve may maintain high benchmark interest rates into 2025 in an effort to curb inflationary pressure on the costs of goods and services across the U.S., which could have the effects of raising the cost of capital and depressing economic growth, either of which-or the combination thereof-could hurt the financial and operating results of our business. To the extent elevated inflation remains, and as a result potential changes in U.S trade policy, including the imposition of tariffs and the resulting consequences, we may experience further cost increases for our operations, including labor costs and equipment. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to timely pass-through the cost increases to our customers, would negatively impact our business, financial condition and results of operations.
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 75.3%, 85.5% and 91.2% of our consolidated revenue for the years ended December 31, 2024, 2023 and 2022, 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.
XTO Energy, Permian Resources and EOG Resources accounted for 19.7%, 14.9% and 10.6%, respectively, of our revenue for the year ended December 31, 2024. If either of these customers were to significantly reduce or discontinue our services, it could have a material adverse effect on our financial condition, results of operations and cash flows. There have been many recent mergers and acquisitions in the oil and gas industry. In May 2024, Pioneer merged with and into a wholly owned subsidiary of ExxonMobil. The Company currently provides pressure pumping, wireline and other services to ExxonMobil and previously provided such services to Pioneer. Mergers and acquisitions involving our customers could negatively impact our future business with them or positively impact our business by providing us access to potential new customers.
We face significant competition that may cause us to lose market share, and competition in our industry has intensified as a result of customer consolidation and industry downturns.
The energy service 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 E&P 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 energy service 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 other factors 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, power generation equipment, 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 energy services and extended lead times to obtain equipment and raw materials needed to provide these services. For example, in 2021 and 2022, there was significant disruption in supply chains around the world caused by the COVID-19 pandemic that 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 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.
Disruption of our supply chain could adversely impact our ability to provide our services.
Our suppliers use multiple forms of transportation to bring their products to market, including truck, ocean and air-cargo shipments. Disruption to the timely supply of raw materials, parts and finished goods or increases in the cost of transportation services, including due to general inflationary pressures, cost of fuel and labor, labor disputes, governmental regulation or governmental restrictions limiting specific forms of transportation, could have an adverse effect on our ability to provide our services, which would adversely affect our results of operations, cash flows and financial position.
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, Chief Commercial Officer and General Counsel could disrupt our operations. We do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
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 energy service 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 physical nature of our operations, 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 energy service 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, the prior administration made climate change a focus of its 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.
Numerous proposals regarding climate change 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 E&P 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, though recently passed laws such as the IRA 2022 advance numerous climate-related objectives. Additionally, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of certain pollutants from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. In December 2023, the EPA finalized a rule that established OOOOb more stringent new source and OOOOc first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Under the final rule, states will have two years to prepare and submit their plans to impose methane emissions controls on existing sources. The presumptive standards under the final rule are generally the same for both new and existing sources, including enhanced leak detection using optical gas imaging and subsequent repair equipment, and reduction of emissions by 95% through capture and control systems. The rule also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a "super-emitter" response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties, triggering certain investigation and repair requirements, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. However the EPA’s final rule is currently being challenged by 23 states and a coalition of industry groups in the U.S Circuit Court of Appeals for the D.C. Circuit. Additionally, at this time, it remains uncertain as to whether the current administration will repeal or modify this rule and the timing with respect to the same. Notwithstanding this, failure to comply with these new methane rules may result in substantial fines and penalties for non-compliance, as well as injunctive relief. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas such as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored Paris Agreement, requires member states to submit non-
binding, individually-determined reduction goals known as NDCs every five years after 2020. The United States rejoined the Paris Agreement in January 2021 and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below 2005 levels by 2030. However, in January 2025, the current President signed an Executive Order once again withdrawing the United States from the Paris Agreement and from any other commitments made under the United Nations Framework Convention on Climate Change. The full impact of these recent developments is uncertain 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. For example, in January 2024 the government announced a temporary pause on pending decisions on liquefied natural gas exports to certain countries. However, upon taking office, the current President signed an Executive Order resuming the processing of permit applications for such projects. 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. Additionally on January 26, 2024, the former president announced a temporary pause on pending decisions on new exports of LNG to countries that the United States does not have free trade agreements with, pending Department of Energy review of the underlying analyses for authorizations. The pause was intended to provide time to integrate certain considerations, including potential energy cost increases for consumers and manufacturers and the latest assessment of the impact of GHG emissions, to ensure adequate guards against health risks. The Department of Energy finalized its study in December 2024. However, upon taking office, the current President signed an Executive Order resuming the processing of permit applications for such projects. At this time, it is unclear what actions the Presidential Administration may take, if at all, with respect to the Department of Energy’s study. 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.
There have also recent been increasing financial risks for companies in the fossil fuel sector as certain 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 although this trend has waned recently and several high-profile banks and institutional investors have withdrawn from various associations that aim to limit financing of industries that emit significant GHG emissions. Any 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. Separately, the SEC released a final rule on climate-related disclosures on March 6, 2024, requiring the disclosure of certain climate-related risks and financial impacts, as well as GHG emissions, which was subsequently stayed by the U.S. Court of Appeals for the Fifth Circuit. The future of the rule remains uncertain at this time given the litigation; however, on February 11, 2025, SEC Acting Chairman Mark T. Uyeda released a public statement and notified the U.S. Court of Appeals for the Eighth Circuit (where the challenges are consolidated) to hold off scheduling argument in the case to provide time for the SEC to further deliberate the final rule and determine next steps. Relatedly, certain states have enacted or are otherwise considering disclosure requirements for certain climate-related risks. Enhanced climate-related disclosure requirements could increase our operating costs and lead to reputational or other harm with customers, regulators, or other stakeholders to the extent our disclosures do not meet their own standards or expectations. Consequently, we are also exposed to increased litigation risks relating to alleged climate-related damages resulting from our operations, statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimation required with respect to calculating and reporting GHG emissions. We also cannot predict how financial institutions and investors might consider any information disclosed under any such requirements when making investment decisions, and as a result it is possible that we could face increases with respect to the costs of, or restrictions imposed on, our access to capital.
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 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 government. For example, in March 2024 the BLM finalized a rule that requires operators to limit flaring from well sites on federal lands, and allows the delay or denial of permits if BLM finds that an operator’s methane waste minimization plan is insufficient. The rule was challenged by various states in the District Court of North Dakota and, in September 2024, the court ordered that the rule cannot be enforced within the plaintiff states pending the outcome of the litigation. Although the rule is currently being implemented in areas not covered by the order, the future of the rule is uncertain. Additionally in January 2021, the president issued an executive order suspending new leasing activities, but not operations under existing leases, for oil and gas E&P on non-Native American 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 leasing pause was effectively halted by a permanent injunction in August 2022, 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. In April 2024, the BLM finalized a rule updating the fiscal terms of federal oil and gas leases, increasing fees, rents, royalties, and bonding requirements. The rule also adds new criteria for BLM to consider when determining whether to lease nominated land, including the presence of important habitats or wetlands, the presence of historical properties or sacred sites, and recreational use of the land. 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 previous 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. The Gardendale Seismic Response area has since been expanded in response to an additional earthquake in December 2022, covering 17 additional wells. In December 2023, a further 23 deep disposal well permits were suspended in the Northern Culberson-Reeves Seismic Response Area. 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 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-related matters, and technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for energy 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. The IRA 2022 appropriates significant federal funding for renewable energy initiatives, which could accelerate the use and commercial viability of alternative energy sources and decrease demand for oil and natural gas. The IRA 2022 has incentivized the further development of and investment in clean energy through the use of tax credits, and future legislation could expand these benefits for alternative energy sources. In addition, legislation has been previously proposed that would make changes to certain U.S. federal income tax provisions currently applicable with respect to oil and natural gas exploration and development companies, including by eliminating the percentage depletion allowance for oil and natural gas properties. While it remains to be seen if the current administration would modify or repeal some or all of the IRA 2022, 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 and regulatory environment.
Moreover, while we may create and publish voluntary disclosures regarding ESG-related matters from time to time, certain statements in those voluntary disclosures may be based on expectations and assumptions or hypothetical scenarios 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 or hypothetical scenarios are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established 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, such targets are often aspirational and 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 pursue or implement such goals because of potential costs or technical or operational obstacles.
Additionally, certain statements or initiatives with respect to ESG-related matters that we may pursue or assert are increasingly subject to heightened scrutiny from the public and governmental authorities, as well as other parties. For example, the SEC has recently taken enforcement action against companies for ESG-related misconduct, including alleged “greenwashing,” (i.e., the process of conveying misleading information or making false claims that overstate potential ESG benefits). Certain regulators, such as the SEC and various state agencies, as well as nongovernmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG statements, goals or standards were misleading, false or otherwise deceptive. Additionally, certain employment practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. More recent political developments could mean that we face increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Such sentiment may focus on our environmental commitments (such as reducing GHG emissions) or our pursuit of certain employment practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. As a result, we may be subject to pressure in the media or through other means, such as governmental investigations, enforcement actions, or other proceedings, all of which could adversely affect our reputation, business, financial performance, market access and growth. Accordingly, there may be increased costs related to reviewing, implementing and managing such policies, as well as compliance and litigation risks based both on positions we do or do not take, or work we do or do not perform.
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. While such ratings do not impact all investors’ investment or 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.
Furthermore, employment practices and social initiatives are also the subject of scrutiny by stakeholders, federal agencies, state governments, regulators and other third-parties. The complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. To the extent any enforcement actions or other litigation is brought against us as a result of emerging viewpoints and legal interpretations, our business, financial condition and access to financing may be materially and adversely affected.
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 NOLs may be limited.
As of December 31, 2024, we had approximately $186.1 million of U.S. federal NOLs, all of which will have an unlimited carryforward. As of December 31, 2024, our state net operating losses were approximately $42.8 million and will begin to expire in 2030.
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, 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 future 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.
Changes to applicable tax laws and regulations or exposure to additional tax liabilities could adversely affect our operating results and cash flows.
We are subject to various complex and evolving U.S. federal, state and local tax laws. U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect. Any significant variance in our interpretation of current tax laws or a successful challenge of one or more of our tax positions by the Internal Revenue Service or other tax authorities could increase our future tax liabilities and adversely affect our operating results and cash flows.
Risks Inherent to an Investment in our Common Stock
We are subject to certain requirements of 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.
Effective internal controls are necessary for us to provide reliable financial reports and prevent fraud. If we or our auditors identify and report material weaknesses in internal controls over financial reporting or if we fail to maintain an effective system of internal controls, such instances may result in material misstatements of our financial statements, cause us to fail to meet our reporting obligations, investors may lose confidence in our financial reporting, and our stock price may decline as a result.
Certain provisions of our certificate of incorporation, and bylaws, as well as Delaware law, may discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our 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, 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. In addition, we may issue common stock as consideration in future mergers and acquisitions, as we did in the Silvertip Acquisition. 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.
There can be no assurance that we will purchase all the shares authorized under our share repurchase program or that such program will enhance the long-term value of our share price.
On April 24, 2024, our Board approved an increase and extension to the share repurchase program previously authorized on May 17, 2023. The program permits the share repurchase of up to an additional $100.0 million of the Company’s common stock for a total of $200.0 million and extends the expiration date by one year to May 31, 2025. There is no obligation for us to continue to repurchase or to repurchase any specific dollar amount of stock and the program may be suspended, modified or discontinued at any time without prior notice. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management's assessment of the intrinsic value of our common stock, the market price of the our common stock, general market and economic conditions, available liquidity, compliance with the Company's debt and other agreements, applicable legal requirements, and other considerations. The share repurchase program could affect the price of our stock and increase volatility in the market. We cannot guarantee that we will purchase all of the shares authorized under the share repurchase program or that such program will enhance the long-term value of our share price. In addition, repurchase regulations and taxes may add additional payment burden to the Company from our share repurchase program. In the past, there have been proposals to increase the amount of the U.S. federal stock repurchase excise tax from 1% to 4%, however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any such change could take effect.

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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 303 W. Wall Street, Suite 102, 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 18. 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 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, 2024, there were 102,994,958 shares of common stock outstanding, held of record by five 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.
Dividends
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.
Share Repurchase Program
The following sets forth information with respect to our repurchases of shares of common stock during the three months ended December 31, 2024:
Period Total number of shares purchased Average price paid per share (2)
Total number of shares purchased as part of publicly announced plans or programs (1)
Approximate dollar value of shares that may yet be purchased under the plans or programs (1)
October 1, 2024 to October 31, 2024 353,171 $ 8.15 353,171 $ 89,654,253
November 1, 2024 to November 30, 2024 70,305 $ 7.13 70,305 $ 89,152,858
December 1, 2024 to December 31, 2024 - $ - - $ 89,152,858
Total 423,476 $ 7.98 423,476 $ 89,152,858
(1)On April 24, 2024, the Board approved an increase and extension of the share purchase program previously authorized on May 17, 2023. The program permits the repurchase of up to an additional $100 million of the Company’s common stock for a total of $200 million and extends the expiration date by one year to May 31, 2025. The shares may be repurchased from time to time in open market transactions, block trades, accelerated share repurchases, privately negotiated transactions, derivative transactions or otherwise, certain of which may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act, as amended, in compliance with applicable state and federal securities laws.
(2)The average price paid per share includes commissions.
Performance Graph
The annual 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 (“Updated Peer Group”) on December 31, 2019, and that all dividends were reinvested at the closing prices of the dividend payment dates. The relevant companies included in our Updated Peer Group consists of Liberty Energy Inc., Patterson-UTI Energy, Inc., RPC, Inc., Calfrac Well Services Ltd., Mammoth Energy Services, Inc. and ProFrac Holding Corp. (added in 2024). We have also included our previous peer group (“Former Peer Group”) which did not include ProFrac Holding Corp. in the following graph. The total cumulative dollar returns shown on the graph represent the value that such investments would have had on the last trading date of 2024. 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 Former Peer Group Updated Peer Group Russell 2000 ProPetro Holding Corp.
12/31/2019 $ 100.0 $ 100.0 $ 100.0 $ 100.0
12/31/2020 $ 64.1 $ 64.1 $ 120.0 $ 65.7
12/31/2021 $ 80.3 $ 80.3 $ 137.7 $ 72.0
12/31/2022 $ 153.1 $ 153.1 $ 109.6 $ 92.2
12/31/2023 $ 130.0 $ 106.4 $ 128.1 $ 74.5
12/31/2024 $ 116.6 $ 95.7 $ 142.9 $ 82.9

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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 omits our results of operations and cash flows for the year ended December 31, 2022, and the comparison of our results of operations for the years ended December 31, 2023, and 2022, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on March 13, 2024.
Unless otherwise indicated, references in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” to “ProPetro Holding Corp.,” “the Company,” “we,” “our,” “us” or like terms refer to ProPetro Holding Corp. and its subsidiaries.
Overview
Our Business
We are a leading integrated energy service company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline and other complementary energy and power generation services to leading upstream oil and gas companies engaged in the exploration and production (“E&P”) of North American oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region’s most active and well-capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil-producing areas in the United States, and we believe we are one of the leading providers of completion services in the region.
Our completion services includes our operating segments comprised of hydraulic fracturing, wireline and cementing operations. Our hydraulic fracturing operations account for approximately 75.6% of our total revenues and operations. Our total available hydraulic horsepower (“HHP”) at December 31, 2024, was 1,556,500 HHP, which was comprised of 450,000 HHP of our Tier IV Dynamic Gas Blending (“DGB”) dual-fuel equipment, 294,000 HHP of FORCE® electric-powered equipment and 812,500 HHP of conventional Tier II equipment. Our hydraulic fracturing fleets range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsite. Our equipment has been designed to handle the operating conditions commonly encountered in the Permian Basin and the region’s increasingly high-intensity well completions (including simultaneous hydraulic fracturing ("Simul-Frac"), which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites. In addition, in 2021 and 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and to purchase new Tier IV DGB dual-fuel equipment. As such, we entered into conversion and purchase agreements with our equipment manufacturers and have received all of the converted and new Tier IV DGB dual-fuel equipment by the end of 2023, representing 450,000 HHP of our Tier IV DGB dual-fuel equipment as of December 31, 2024. In 2022, we entered into three-year electric fleet leases for four FORCE® electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet and in June 2024, we entered into an additional three-year lease for a fifth FORCE® electric-powered hydraulic fracturing fleet with 72,000 HHP. As of December 31, 2024, we have received 294,000 HHP of FORCE® electric-powered equipment representing four fleets and a portion of the fifth fleet. We currently expect to receive the remaining equipment associated with the fifth fleet in the first half of 2025.
In the fourth quarter of 2024, we formed a new subsidiary, ProPetro Energy Solutions, LLC, (“PROPWR”) to provide power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. This subsidiary has ordered equipment, but it has not yet begun revenue-generating activities.
On November 1, 2024, we sold our cementing business located in Vernal, Utah, to a business owned by a former employee as part of a strategic repositioning. We received a promissory note for $13.0 million as consideration. The note receivable is
secured by substantially all assets of the former employee’s business and the former employee’s ownership interests in and distributions from the business. The note receivable is to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025, to December 31, 2029. We recorded a gain on disposal of $8.2 million related to the sale of the business. The former employee was part of our cementing operations until November 1, 2024, and is no longer affiliated with the Company.
On May 31, 2024, we consummated the acquisition of all of the outstanding equity interests in Aqua Prop, LLC (“AquaProp”), which provides wet sand solutions for hydraulic fracturing sand requirements at oil well sites (the “AquaProp Acquisition”). The cash consideration for the AquaProp Acquisition includes $13.7 million paid to the seller, $7.2 million paid to settle the seller’s outstanding debt, and $0.3 million paid for the seller’s transaction expenses. As a result of the AquaProp Acquisition, we expanded our operations into the wet sand service business unit.
On December 1, 2023, we consummated the purchase of the assets and operations of Par Five Energy Services LLC (“Par Five”), which provides cementing services in the Delaware Basin, in exchange for $25.4 million of cash, including deferred cash consideration of $3.1 million which is payable to Par Five or its beneficiary on June 1, 2025, with interest of 4.0% per annum (the “Par Five Acquisition”). The Par Five Acquisition complemented our existing cementing business and enabled us to serve both the Midland and Delaware sub-basins of the Permian Basin.
On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC (the “Silvertip Acquisition”), which provides wireline perforation and ancillary services in the Permian Basin in exchange for 10.1 million shares of our common stock valued at $106.7 million, $30.0 million of cash, the payoff of $7.2 million of assumed debt, and the payment of certain other closing and transaction costs. At December 31, 2024, we had 26 wireline units available to provide wireline perforation and ancillary services. Collectively, the AquaProp Acquisition, the Par Five Acquisition and the Silvertip Acquisition have positioned the Company as a more integrated and diversified completions-focused energy service provider. See Note 4. Business Acquisitions in the financial statements for additional disclosures.
We believe that our substantial market presence in the Permian Basin positions us well to capitalize on drilling and completion activity in the region. Primarily, our operational focus has been in the Permian Basin's Midland sub-basin, where our customers have operated. However, we have increased our operations in the Delaware sub-basin and are well-positioned to support further increases to our activity in this area in response to demand from our customers. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.
We have historically conducted our business through four operating segments: hydraulic fracturing, wireline, cementing and coiled tubing. Prior to the fourth quarter of fiscal year 2023, our operating segments met the aggregation criteria and were aggregated into the “Completion Services” reportable segment and our coiled tubing operations (which were divested in September 2022) were shown in the “All Other” category. Effective in the the fourth quarter of fiscal year 2023, we revised our segment reporting as we determined that our three operating segments no longer met the criteria to be aggregated. In the fourth quarter of fiscal year 2024, we formed PROPWR to provide power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. This new subsidiary has ordered equipment, but it has not yet begun revenue-generating activities. Our hydraulic fracturing, wireline and cementing operating segments meet the criteria of a reportable segment. Our divested coiled tubing and our newly formed power generation services segments do not meet the reportable segment criteria and are included within the “All Other” category. Additionally, our corporate administrative activities do not involve business activities from which it may earn revenues and its results are not regularly reviewed by the Company’s Chief Operating Decision Maker (the “CODM”) when making key operating and resource decisions. As a result, corporate administrative expenses have been included under “Reconciling Items.” For additional financial information on our reportable segments presentation, please see reportable segment information in Part II - Item 8, “Financial Statements and Supplementary Data.”
Pioneer Pressure Pumping Acquisition
On December 31, 2018, we consummated the purchase of certain pressure pumping assets and real property from Pioneer Natural Resources USA, Inc. (“Pioneer”) and Pioneer Pumping Services, LLC in the Pioneer Pressure Pumping Acquisition in exchange for 16.6 million shares of our common stock and $110.0 million in cash. In May 2024, Pioneer merged with and into a wholly owned subsidiary of ExxonMobil after which ExxonMobil became the owner of these shares. The Company currently provides pressure pumping, wireline and other services to ExxonMobil and previously provided such services to Pioneer.
On April 22, 2024, we entered into a sub-agreement for hydraulic fracturing services with XTO, a wholly owned subsidiary of ExxonMobil, pursuant to which we will provide hydraulic fracturing, wireline and pumpdown services with two committed FORCE® electric-powered hydraulic fracturing fleets with the option to add a third FORCE® fleet (also with wireline and pumpdown services) for a period of three years or for contracted hours, whichever occurs last with respect to each fleet, subject to certain termination and release rights.
Commodity Price and Other Economic Conditions
The oil and gas industry has traditionally been volatile and is characterized by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, war and political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control.
The geopolitical and macroeconomic consequences of military action in the Middle East, the Russian invasion of Ukraine, including the associated sanctions, and the adverse impacts of the COVID-19 pandemic have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing. As the global response to the COVID-19 pandemic began to wane, the demand and prices for crude oil increased from the lows experienced in 2020, with the WTI average crude oil price reaching approximately $94 per barrel in 2022, the highest average price in the prior ten years. However, the WTI average crude oil price declined to approximately $78 per barrel in 2023 and approximately $76 per barrel in 2024. We believe that the volatility of crude oil prices in recent years has been partly driven by declines in crude oil supplies, concerns over sanctions resulting from Russia's invasion of Ukraine, concerns over a potential disruption of Middle Eastern oil supplies resulting from the conflict in the Middle East, slower crude oil production growth due to the lack of reinvestment in the oil and gas industry in the last three years, the extension of OPEC+ production cuts of approximately 3.9 million barrels per day originally announced in 2023, and concerns of a potential global recession resulting from high inflation and interest rates.
With the significant increase in global crude oil prices from 2021, including the WTI crude oil price, there was a significant increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of 2022, according to the Baker Hughes. Following the increase in rig count and the WTI crude oil price, the energy service industry has experienced increased demand for its completion services, and improved pricing. However, the Permian Basin rig count experienced a 13% decrease in 2023 to 309 at the end of 2023 and further decreased to 304 at the end of 2024 which resulted in a reduction in the demand for completion services and pressure on pricing of our services.
Sustained levels of high inflation likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including interest rates, labor costs and equipment. We cannot predict any future trends in the rate of inflation and crude oil prices. A significant increase in or continued high levels of inflation, to the extent we are unable to timely pass-through the cost increases to our customers, further declines in crude oil prices, or potential change in U.S trade policy, including the imposition of tariffs and the resulting consequences, would negatively impact our business, financial condition and results of operations. See Part II, Item 1A. “Risk Factors-We may be adversely affected by the effects of inflation.”
Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including upstream and energy service companies. As a result, we are working with our customers and equipment manufacturers to transition our equipment to a lower emissions profile. Currently, a number of lower emission solutions for pumping equipment, including Tier IV DGB dual-fuel, FORCE® electric, direct drive gas turbine and other technologies have been developed, and we expect additional lower emission solutions will be developed in the future. We are continually evaluating these technologies and other investment and acquisition opportunities that would support our existing and new customer relationships. The transition to lower emissions equipment is quickly evolving and will be capital intensive. Over time, we may be required to convert substantially all of our conventional Tier II equipment to lower emissions equipment. We have transitioned our hydraulic fracturing available equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022, 60% in 2023, 70% in 2024, and expect to increase to approximately 75% by the end of the first quarter of 2025. To the extent any of our customers have certain expectations or requirements with respect to emissions reductions from their contractors, if we are unable to continue quickly transitioning to lower emissions equipment, the demand for our services could be adversely impacted.
If the Permian Basin rig count and market conditions improve, including improved pricing for our services and labor availability, and we are able to meet our customers' lower emissions equipment demands, we believe our operational and
financial results will also continue to improve. If the rig count or market conditions do not improve or decline in the future, and we are unable to increase our pricing or pass-through future cost increases to our customers, there could be a material adverse impact on our business, results of operations and cash flows.
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.
2024 Operational Highlights
Over the course of the year ended December 31, 2024:
•we deployed two FORCE® electric-powered hydraulic fracturing fleets with a total capacity of 120,000 HHP. Four FORCE® electric-powered hydraulic fracturing fleets are now operating under contract with leading customers;
•our available equipment portfolio is expected to be comprised of approximately 75% lower emissions (FORCE® electric and Tier IV DGB dual-fuel), and 25% conventional diesel equipment by the end of 2025;
•despite market volatility, our average active hydraulic fracturing fleet count was approximately 14 fleets, a decrease from 15 active fleets in 2023;
•we published our second annual sustainability report, which describes our commitment to building a sustainable business that supports the safe, reliable production of the energy the world needs by offering competitive, value-driving services to customers, while benefitting our shareholders, communities, and other stakeholders;
•we consummated the purchase of all of the outstanding equity interests in AquaProp on May 31, 2024, which provides wet sand solutions for hydraulic fracturing sand requirements at oil well sites; and
•we formed PROPWR in the fourth quarter of 2024, to provide power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers. This subsidiary has ordered equipment, but has not yet begun revenue-generating activities.
2024 Financial Highlights
Financial highlights for the year ended December 31, 2024:
•net loss was $137.9 million, compared to net income of $85.6 million for the year ended December 31, 2023. Diluted net loss per common share was $1.31, compared to diluted net income of $0.76 for the year ended December 31, 2023. Net loss for included property and equipment impairment expense of $188.6 million related to our conventional Tier II diesel-only hydraulic fracturing pumping units and associated conventional assets and goodwill impairment expense of $23.6 million related to the goodwill in our wireline operating segment. Adjusted EBITDA of approximately $283.2 million decreased 29.9%, compared to $404.0 million for the year ended December 31, 2023 (see reconciliation of Adjusted EBITDA to net income in the subsequent section “How We Evaluate Our Operations”);
•capital expenditures were reduced to $133.4 million or 57% as compared to 2023;
•net cash provided by operating activities less net cash used in investing activities improved by $106.6 million compared to 2023;
•our accounts receivable to accounts payable ratio increased to 2.1 from 1.5. Working capital (current assets less current liabilities) increased to $70.0 million from $39.7 million;
•our total liquidity was $160.9 million as of December 31, 2024. consisting of cash and cash equivalents of $50.4 million and remaining availability of $110.5 million under our ABL Credit Facility; we had $45.0 million of borrowings as of December 31, 2024, under our ABL Credit Facility; and
•the Company repurchased and retired 7.2 million shares of common stock for an aggregate of $59.1 million, an average price per share of $8.21 including commissions, under the share repurchase program. As of December 31, 2024, $89.2 million remained authorized for future repurchases of common stock under the share repurchase program.
Our Assets and Operations
Completion services includes our hydraulic fracturing, wireline and cementing operations. We primarily provide these services to E&P companies in the Permian Basin. During the year ended December 31, 2024, our hydraulic fracturing, wireline and cementing operations accounted for 75.6%, 14.1%, and 10.3% of our total revenue, respectively. Our equipment has been designed to handle Permian Basin specific operating conditions and the region’s increasingly high-intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. We plan to continually reinvest in our equipment to ensure optimal performance and reliability.
How We Generate Revenue
We generate revenue through our completion services, and more specifically, by providing hydraulic fracturing services to our customers. We operate a fleet of mobile hydraulic fracturing, wireline and cementing units and other auxiliary equipment to perform completion services to E&P companies. We also provide personnel and services that are tailored to meet each of our customers’ needs.
Hydraulic fracturing operations account for a significant portion of our total revenue. We charge our customers on a per-job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant and chemicals to be used and other parameters of the job.
In addition to hydraulic fracturing services, we generate revenue through other completion services that we provide to our customers, including wireline, cementing and other related services. These completion services are complementary to each other and are undertaken in unison with hydraulic fracturing services. They are provided through various contractual arrangements, including on a turnkey contract basis, in which we set a price to perform a particular job, or a daywork contract basis, in which we are paid a set price per day for our services. We are also sometimes paid by the hour for these complementary services.
Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil price per barrel was approximately $76, $78, and $94 for the years ended December 31, 2024, 2023, and 2022, respectively. In January 2025, the WTI oil price was approximately $74 per barrel. If the WTI oil price declines in the future or remains highly volatile, demand for our services may be negatively impacted, which could result in a significant decrease in our future profitability and cash flows. We monitor oil and natural gas prices and the Permian Basin rig count to enable us to more effectively plan our business and forecast the demand for our services.
The historical weekly average Permian Basin rig count based on Baker Hughes rig count information was as follows:
Year Ended December 31,
Drilling Rig Type (Permian Basin) 2024 2023 2022
Directional 3 3 3
Horizontal 296 323 318
Vertical 10 9 14
Total 309 335 335
Average Permian Basin rig count to U.S. rig count 51.6 % 48.7 % 46.3 %
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 30.2% and 28.7% of total costs of service for the years ended December 31, 2024, and 2023, respectively. The increase in our direct labor costs percentage is driven by wage adjustments and higher headcount resulting from business acquisitions.
Expendables. Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our completion services and other operations. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services. Expendable product costs comprised approximately 25.7% and 32.9% of total costs of service for the years ended
December 31, 2024, and 2023, respectively. The percentage decrease in our expendables was primarily attributable to certain customers electing to directly source sand and the associated logistics.
Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental, lease costs on our FORCE® electric-powered hydraulic fracturing fleets, and other miscellaneous operating expenses. Fuel is consumed both in the operation and movement of our equipment. Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs. Capital expenditures to upgrade or extend the useful life of equipment are capitalized and are not included in other direct costs. Other direct costs were 44.1% and 38.4% of total costs of service for the years ended December 31, 2024, and 2023, respectively. The percentage increase in our other direct costs was primarily attributable to lease costs on our FORCE® fleets.
How We Evaluate Our Operations
Our management uses Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.
Adjusted EBITDA and Adjusted EBITDA Margin
We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our earnings, before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets and businesses, (ii) stock-based compensation, (iii) business acquisition contingent consideration adjustments, (iv) other expense/(income), (v) other unusual or nonrecurring (income)/expenses, such as impairment expenses, costs related to asset acquisitions, insurance recoveries, one-time professional fees and legal settlements and (vi) retention bonuses and severance expense. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.
Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, and research analysts, to assess our financial performance because it allows us and other users to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization), nonrecurring (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 accounting principles generally accepted in the United States of America (“GAAP”).
Note Regarding Non-GAAP Financial Measures
Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP (“non-GAAP”), except when specifically required to be disclosed by GAAP in the financial statements. We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure, asset base, nonrecurring expenses (income) and items outside the control of the Company. Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA. Adjusted EBITDA and Adjusted EBITDA margin should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider Adjusted EBITDA and Adjusted EBITDA margin in isolation or as a substitute for an analysis of our results as reported under GAAP. Because Adjusted EBITDA and Adjusted EBITDA margin may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
The following tables set forth certain financial information with respect to the Company’s reportable segments; intersegment revenues are shown under “Reconciling Items” (in thousands):
Hydraulic Fracturing Wireline Cementing All Other Reconciling Items Total
Year ended December 31, 2024
Service revenue $ 1,092,000 $ 203,182 $ 149,411 $ - $ (307) $ 1,444,286
Adjusted EBITDA $ 270,505 $ 43,857 $ 26,539 $ (370) $ (57,288) $ 283,243
Depreciation and amortization $ 182,188 $ 20,633 $ 8,812 $ - $ 100 $ 211,733
Property and equipment impairment expense (1)
$ 188,601 $ - $ - $ - $ - $ 188,601
Goodwill impairment expense (2)
$ - $ 23,624 $ - $ - $ - $ 23,624
Operating lease expense on FORCE® fleets (3)
$ 47,141 $ - $ - $ - $ - $ 47,141
Capital expenditures $ 116,257 $ 7,713 $ 9,376 $ - $ 42 $ 133,388
Goodwill $ 920 $ - $ - $ - $ - $ 920
Total assets $ 961,485 $ 156,349 $ 73,935 $ - $ 31,876 $ 1,223,645
Hydraulic Fracturing Wireline Cementing All Other Reconciling Items Total
Year ended December 31, 2023
Service revenue $ 1,280,523 $ 229,599 $ 120,277 $ - $ - $ 1,630,399
Adjusted EBITDA $ 366,809 $ 61,930 $ 24,665 $ - $ (49,444) $ 403,960
Depreciation and amortization $ 156,057 $ 18,762 $ 5,845 $ - $ 222 $ 180,886
Operating lease expense on FORCE® fleets (3)
$ 5,087 $ - $ - $ - $ - $ 5,087
Capital expenditures $ 294,377 $ 12,203 $ 3,440 $ - $ - $ 310,020
Goodwill $ - $ 23,624 $ - $ - $ - $ 23,624
Total assets $ 1,189,526 $ 198,957 $ 78,475 $ - $ 13,354 $ 1,480,312
Hydraulic Fracturing Wireline Cementing All Other Reconciling Items Total
Year ended December 31, 2022
Service revenue $ 1,143,216 $ 31,188 $ 91,857 $ 13,440 $ - $ 1,279,701
Adjusted EBITDA $ 339,186 $ 7,926 $ 14,897 $ (1,463) $ (43,956) $ 316,590
Depreciation and amortization $ 117,753 $ 2,619 $ 5,089 $ 2,240 $ 407 $ 128,108
Property and equipment impairment expense (1)
$ 57,454 $ - $ - $ - $ - $ 57,454
Capital expenditures $ 347,757 $ 2,265 $ 7,769 $ 1,876 $ 5,649 $ 365,316
Goodwill $ - $ 23,624 $ - $ - $ - $ 23,624
Total assets $ 1,092,658 $ 173,489 $ 46,944 $ - $ 22,695 $ 1,335,786
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(1)Represents noncash property and equipment impairment expense on our conventional Tier II diesel-only hydraulic fracturing pumps and associated conventional assets (“Tier II Units”) for the year ended December 31, 2024, and noncash impairment expense on our DuraStim® electric-powered hydraulic fracturing equipment for the year ended December 31, 2022. There was no property and equipment impairment expense for the year ended December 31, 2023.
(2)Represents noncash impairment of goodwill in our wireline operating segment.
(3)Represents amortization of right-of-use assets and interest expense on lease liabilities related to operating leases on our FORCE® electric-powered hydraulic fracturing fleets. This cost is recorded within cost of services in our consolidated statements of operations. We did not have this cost for the year ended December 31, 2022.
A reconciliation of net (loss) income to Adjusted EBITDA is provided in the table below (in thousands):
Year Ended December 31,
2024 2023 2022
Net (loss) income $ (137,859) $ 85,634 $ 2,030
Depreciation and amortization 211,733 180,886 128,108
Property and equipment impairment expense (1)
188,601 - 57,454
Goodwill impairment expense (2)
23,624 - -
Interest expense 7,815 5,308 1,605
Income tax (benefit) expense (31,385) 29,868 5,356
Loss on disposal of assets and businesses, net 7,451 73,015 102,150
Stock-based compensation 17,288 14,450 21,881
Business acquisition contingent consideration adjustments (2,600) - -
Other (income) expense, net (3)
(5,531) 9,533 (11,582)
Other general and administrative expense, net (4)
1,782 2,969 8,460
Retention bonus and severance expense 2,324 2,297 1,128
Adjusted EBITDA $ 283,243 $ 403,960 $ 316,590
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(1)Represents noncash property and equipment impairment expense on our Tier II Units for the year ended December 31, 2024, and noncash impairment expense on our DuraStim® electric-powered hydraulic fracturing equipment for the year ended December 31, 2022. These impairment expenses are included in our Hydraulic Fracturing reportable segment.
(2)Represents noncash impairment of goodwill in our wireline operating segment.
(3)Other income for the year ended December 31, 2024 is primarily comprised of tax refunds (net of advisory fees) totaling $5.0 million and insurance reimbursements of $2.0 million, partially offset by a $2.0 million loss to a customer related to an accidental cementing job failure. Other expense for the year ended December 31, 2023 is primarily comprised of settlement expenses resulting from routine audits and true-up health insurance costs totaling approximately $7.4 million and a $2.5 million unrealized loss on short-term investment. Other income for the year ended December 31, 2022 includes tax refunds (net of advisory fees) totaling $10.7 million, a $2.7 million noncash income from fixed asset inventory received as part of a settlement of warranty claims with an equipment manufacturer, and a $1.6 million unrealized loss on short-term investment.
(4)Other general and administrative expense for the years ended December 31, 2024 and 2023 primarily relates to nonrecurring professional fees paid to external consultants in connection with our business acquisitions and legal settlements, net of reimbursements from insurance carriers. Other general and administrative expense for the year ended December 31, 2022 primarily relates to nonrecurring professional fees paid to external consultants in connection with the Company's audit committee review, SEC investigation, shareholder litigation, legal settlements and other legal matters, net of reimbursements from insurance carriers.
Results of Operations
In 2024, we conducted our business through four operating segments: hydraulic fracturing, wireline, cementing, and power generation services (started in the fourth quarter of fiscal year 2024 and has not begun any revenue-generating activities yet). Our power generation services operating segments are shown in the “All Other” category for segment reporting purposes.
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
(in thousands, except percentages)
Year Ended December 31, Change
2024 2023 Variance %
Revenue
Hydraulic Fracturing $ 1,092,000 $ 1,280,523 $ (188,523) (14.7) %
Wireline 203,182 229,599 (26,417) (11.5) %
Cementing 149,411 120,277 29,134 24.2 %
Elimination of intersegment service revenue (307) - (307) 100.0 %
Total revenue 1,444,286 1,630,399 (186,113) (11.4) %
Cost of services (1)
Hydraulic Fracturing 800,202 886,157 (85,955) (9.7) %
Wireline 148,125 155,357 (7,232) (4.7) %
Cementing 117,490 90,287 27,203 30.1 %
All Other (2)
4 - 4 100.0 %
Elimination of intersegment cost of services (307) - (307) 100.0 %
Total cost of services 1,065,514 1,131,801 (66,287) (5.9) %
General and administrative expense (3)
114,323 114,354 (31) - %
Depreciation and amortization 211,733 180,886 30,847 17.1 %
Property and equipment impairment expense 188,601 - 188,601 100.0 %
Goodwill impairment expense 23,624 - 23,624 100.0 %
Loss on disposal of assets and business, net 7,451 73,015 (65,564) (89.8) %
Interest expense 7,815 5,308 2,507 47.2 %
Other (income) expense, net (5,531) 9,533 (15,064) (158.0) %
Income tax (benefit) expense (31,385) 29,868 (61,253) (205.1) %
Net (loss) income $ (137,859) $ 85,634 $ (223,493) (260.99) %
Adjusted EBITDA (4)
$ 283,243 $ 403,960 $ (120,717) (29.88) %
Adjusted EBITDA Margin (4)
19.6 % 24.8 % (5.2) % (20.97) %
Hydraulic Fracturing segment results of operations:
Revenue $ 1,092,000 $ 1,280,523 $ (188,523) (14.7) %
Cost of services $ 800,202 $ 886,157 $ (85,955) (9.7) %
Adjusted EBITDA $ 270,505 $ 366,809 $ (96,304) (26.3) %
Adjusted EBITDA Margin (5)
24.8 % 28.6 % (3.8) % (13.3) %
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(1) Exclusive of depreciation and amortization.
(2) Includes our newly formed power generation services business.
(3) Inclusive of stock-based compensation.
(4) For definitions of the non-GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin to our most directly comparable financial measures calculated in accordance with GAAP, please read “How We Evaluate Our Operations.”
(5) The non-GAAP financial measure of Adjusted EBITDA margin for the Hydraulic Fracturing segment is calculated by taking Adjusted EBITDA for the Hydraulic Fracturing segment as a percentage of our revenues for the Hydraulic Fracturing segment.
Revenue. Revenue decreased 11.4%, or $186.1 million, to $1,444.3 million for the year ended December 31, 2024, as compared to $1,630.4 million for the year ended December 31, 2023. Revenue by reportable segment was as follows:
Hydraulic Fracturing. Our hydraulic fracturing segment revenues decreased 14.7%, or $188.5 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The decrease was primarily attributable to a decrease in our customers’ activity levels as a result of a decrease in drilling activity and decreased customer pricing, partially offset by the addition of AquaProp's operations in May 2024, which contributed $44.1 million in revenues during 2024. Our average active hydraulic fracturing fleet count was approximately 14 fleets for the year ended December 31, 2024, a decrease from 15 fleets for the year ended December 31, 2023. Intersegment revenues, consisting of revenues derived from our wireline segment, totaled $0.3 million and $0 for the years ended December 31, 2024 and 2023, respectively.
Wireline. Our wireline segment revenue decreased 11.5%, or $26.4 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The decrease was primarily attributable to a decrease in our customers' activity levels as a result of a decrease in drilling activity and decreased customer pricing.
Cementing. Our cementing segment revenue increased 24.2%, or $29.1 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The increase was primarily attributable to the addition of Par Five's operations in December 2023, which contributed to $35.3 million of the increase in revenues.
Cost of Services. Cost of services decreased 5.9%, or $66.3 million, to $1,065.5 million for the year ended December 31, 2024, from $1,131.8 million during the year ended December 31, 2023. Cost of services by reportable segment was as follows:
Hydraulic Fracturing. Cost of services for our hydraulic fracturing segment decreased $86.0 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023. As a percentage of hydraulic fracturing segment revenues (including equipment reservation fees), hydraulic fracturing cost of services was 73.3% for the year ended December 31, 2024, as compared to 69.2% for the year ended December 31, 2023 driven by the decreased activity levels, customer price decreases and the impact of general cost inflation. The decrease in cost of services was partially offset by an increase of $7.6 million in insurance expense resulting from higher allocation of workers' compensation, general liability and automobile insurance costs to cost of services in 2024 compared to 2023 since these costs are primarily incurred for our operational workforce, and the addition of AquaProp's operations in May 2024, which added $42.5 million in cost of services during the year ended December 31, 2024.
Wireline. Our wireline segment cost of services decreased 4.7%, or $7.2 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023 due to scaling back in response to decreased revenues. Intersegment cost of services, consisting of cost of services incurred to our hydraulic fracturing segment, totaled $0.3 million and $0 for the years ended December 31, 2024 and 2023, respectively.
Cementing. Our cementing cost of services increased 30.1%, or $27.2 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The increase was primarily attributable to the addition of Par Five's operations in December 2023, which resulted in $27.9 million of the net increase in cost of services.
General and Administrative Expenses. General and administrative expenses remained flat at $114.3 million for the year ended December 31, 2024, as compared to $114.4 million for the year ended December 31, 2023.
Excluding nonrecurring and noncash items (i.e., stock-based compensation of $17.3 million, legal settlements (net of insurance reimbursements) of $0.2 million, transaction expenses of $1.6 million and retention bonuses and severance expenses of $2.3 million, partially offset by business acquisition contingent consideration adjustments of $2.6 million), general and administrative expenses were $95.5 million for the year ended December 31, 2024, as compared to $94.6 million for the year ended December 31, 2023.
Depreciation and Amortization. Depreciation and amortization increased 17.1%, or $30.8 million, to $211.7 million for the year ended December 31, 2024, as compared to $180.9 million for the year ended December 31, 2023. The increase was
primarily attributable to (i) assets placed into service since December 31, 2023, (ii) the addition of a finance lease for certain power generation equipment in August 2023 which resulted in $19.0 million of amortization, (iii) the addition of Par Five's operations in December 2023 which resulted in a $3.5 million increase in depreciation and (iv) the addition of AquaProp's operations in May 2024 which included $3.5 million of depreciation and amortization.
Property and Equipment Impairment Expense. During the year ended December 31, 2024, we recorded noncash property and equipment impairment expense of $188.6 million in connection with the impairment of our Tier II Units, which is included in our Hydraulic Fracturing reportable segment. No property and equipment impairment expense was recorded during the year ended December 31, 2023.
Goodwill Impairment Expense. During the year ended December 31, 2024, we recorded goodwill impairment expense of $23.6 million in our Wireline reportable segment during the year ended December 31, 2024. No goodwill impairment expense was recorded during the year ended December 31, 2023.
Loss on Disposal of Assets and Business. Loss on the disposal of assets and business decreased 89.8%, or $65.5 million, to $7.5 million for the year ended December 31, 2024, as compared to $73.0 million for the year ended December 31, 2023. The decrease was primarily attributable to an $8.2 million gain related to the sale of our cementing business located in Vernal, Utah, during 2024, losses incurred during 2023 from the decommissioning of certain hydraulic fracturing equipment, replacement of certain major components in connection with our conversion of certain Tier II hydraulic fracturing equipment to Tier IV DGB, and the write-off of certain hydraulic fracturing equipment as a result of an accidental fire at a wellsite in March 2023.
Interest Expense. Interest expense increased to $7.8 million for the year ended December 31, 2024, as compared to $5.3 million for the year ended December 31, 2023. The increase was primarily attributable to higher average outstanding borrowings under our ABL Credit Facility during the year ended December 31, 2024 and the addition of a finance lease for certain power generation equipment in August 2023.
Other (Income) Expense. Other income was approximately $5.5 million for the year ended December 31, 2024, as compared to other expense of $9.5 million for the year ended December 31, 2023. Other income during the year ended December 31, 2024 is primarily comprised of tax refunds (net of advisory fees) totaling $5.0 million, insurance reimbursements of $2.0 million and a $2.6 million decrease in estimated fair value of the contingent consideration payable on our acquisition of AquaProp, partially offset by a $2.0 million loss to a customer related to an accidental cementing job failure. Other expense for the year ended December 31, 2023 is comprised of settlement expenses resulting from routine audits and true-up health insurance costs totaling approximately $7.4 million and a $2.5 million unrealized loss on short-term investment.
Income Taxes. Total income tax benefit was $31.4 million resulting in an effective tax rate of 18.5% for the year ended December 31, 2024, as compared to income tax expense of $29.9 million resulting in an effective tax rate of 25.9% for the year ended December 31, 2023. The change in income tax benefit recorded during the year ended December 31, 2024, compared to the change in income tax expense recorded during the year ended December 31, 2023, is primarily attributable to the difference in the impact of nondeductible expenses and state taxes on the pre-tax loss for 2024, as compared to pre-tax income for 2023.
Liquidity and Capital Resources
Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility (as defined below). Our cash is primarily used to fund our operations, support growth opportunities, fund share repurchases under our share repurchase program and satisfy future debt payments. Our Borrowing Base (as defined below), as redetermined monthly, is tied to the sum of 85% to 90% of monthly eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the Borrowing Base), in each case, depending on the credit ratings of our accounts receivable counterparties, less customary reserves. Changes to our operational activity levels and our customers’ credit ratings have an impact on our total eligible accounts receivable, which could result in significant changes to our Borrowing Base and, therefore, our availability under our ABL Credit Facility.
We received advance payments from a customer for our services, and the amount outstanding in connection with the advance payments was $11.8 million and $19.2 million as of December 31, 2024 and 2023, respectively. There were no amounts of restricted cash as of December 31, 2024 and 2023.
As of December 31, 2024, our borrowings under our ABL Credit Facility were $45.0 million and our total liquidity was $160.9 million, consisting of cash and cash equivalents of $50.4 million and $110.5 million of availability under our ABL Credit Facility.
On April 24, 2024, the Company's board of directors (the “Board”) approved an increase and extension to the share repurchase program previously authorized on May 17, 2023. The program permits the repurchase of up to an additional $100 million of the Company’s common stock for a total of $200 million and extends the expiration date by one year to May 31, 2025. The shares may be repurchased from time to time in open market transactions, block trades, accelerated share repurchases, privately negotiated transactions, derivative transactions or otherwise, certain of which may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act, as amended, in compliance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management's assessment of the intrinsic value of the Company's common stock, the market price of the Company's common stock, general market and economic conditions, available liquidity, compliance with the Company's debt and other agreements, applicable legal requirements, and other considerations. The Company is not obligated to purchase any shares under the share repurchase program, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund the repurchases using cash on hand and expected free cash flow to be generated through May 2025. During the year ended December 31, 2024, the Company repurchased and retired 7.2 million shares of common stock for an aggregate of $59.1 million, an average price per share of $8.21 including commissions, under the share repurchase program. As of December 31, 2024, $89.2 million remained authorized for future repurchases of common stock under the share repurchase program.
On May 31, 2024, the Company consummated the acquisition of all of the outstanding equity interests in AquaProp, which provides wet sand solutions for hydraulic fracturing sand requirements at oil well sites. The cash consideration for this acquisition includes $13.7 million paid to the seller, $7.2 million paid to settle the seller’s outstanding debt, and $0.3 million paid for the seller’s transaction expenses.
On November 1, 2024, we sold our cementing business located in Vernal, Utah, to a business owned by a former employee as part of a strategic repositioning. We received a promissory note for $13.0 million as consideration. The note receivable is secured by substantially all assets of the former employee’s business and the former employee’s ownership interests in and distributions from the business. The note receivable is to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025 to December 31, 2029. We recorded a gain on disposal of $8.2 million related to the sale of the business. The former employee was part of our cementing operations until November 1, 2024 and is no longer affiliated with the Company.
There can be no assurance that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures and to continue with our share repurchases under our share repurchase program or fund future business acquisitions. Future cash flows are subject to a number of variables, and are highly dependent on the drilling and completion, and production activity by our customers, which in turn is highly dependent on oil and natural gas prices. Depending upon market conditions and other factors, we may issue equity and debt securities or take other actions necessary to fund our business, strategy or meet our future long-term liquidity requirements.
Cash and Cash Flows
The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2024 and 2023, respectively.
Year Ended December 31,
(in thousands)
2024 2023
Net cash provided by operating activities
$ 252,295 $ 374,742
Net cash used in investing activities
$ (155,099) $ (384,127)
Net cash used in financing activities
$ (80,107) $ (46,123)
Operating Activities
Net cash provided by operating activities was $252.3 million for the year ended December 31, 2024, as compared to $374.7 million for the year ended December 31, 2023. The net decrease of $122.4 million was primarily due to lower net income adjusted for noncash expenses and the timing of our receivable collections from our customers and payments to our vendors.
Investing Activities
Net cash used in investing activities decreased to $155.1 million for the year ended December 31, 2024, from $384.1 million for the year ended December 31, 2023. The decrease was primarily attributable to our capital light strategy and the completion of our planned investments in Tier IV DGB equipment.
The following table summarizes our capital expenditures incurred by reportable segment for the periods indicated:
Year Ended December 31,
(in thousands) 2024 2023
Reportable Segments:
Hydraulic Fracturing $ 116,257 $ 294,377
Wireline 7,713 12,203
Cementing 9,376 3,440
Reconciling Items (1)
42 -
Total capital expenditures (2)
$ 133,388 $ 310,020
_________________
(1) Reconciling Items include our corporate facilities.
(2) See Note 3. Supplemental Cash Flows Information in the financial statements for noncash reconciling items.
Financing Activities
Net cash used in financing activities increased to $80.1 million for the year ended December 31, 2024, compared to $46.1 million for the year ended December 31, 2023. The net increase was primarily driven by net borrowings of $15.0 million under our ABL Credit Facility during the year ended December 31, 2023, a $13.0 million increase in payments of finance lease obligation and a $7.4 million increase in share repurchases and repayments of insurance financing of $1.0 million during the year ended December 31, 2024, partially offset by a $1.6 million decrease in tax withholdings paid for net settlement of equity awards and payment of debt issuance costs of $1.2 million during the year ended December 31, 2023.
Credit Facility and Other Financing Arrangements
Our revolving credit facility, as amended and restated in April 2022, prior to giving effect to the amendment to the revolving credit facility in June 2023, had a total borrowing capacity of $150.0 million. The revolving credit facility had a borrowing base of 85% to 90%, depending on the credit ratings of our accounts receivable counterparties, of monthly eligible accounts receivable less customary reserves. The revolving credit facility included a springing fixed charge coverage ratio to apply when excess availability was less than the greater of (i) 10% of the lesser of the facility size or the borrowing base or (ii) $10.0 million. Under the revolving credit facility we were 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.
Effective June 2, 2023, the Company entered into an amendment to its amended and restated revolving credit facility. The amendment increased the borrowing capacity under the ABL Credit Facility to $225.0 million (subject to the Borrowing Base limit), and extended the maturity date to June 2, 2028.
Effective June 26, 2024, the company entered into an amendment to its amended and restated revolving credit facility (the revolving credit facility, as amended and restated in April 2022, as amended in June 2023, as amended in June 2024 and as may be amended further, the “ABL Credit Facility”). The amendment increased the amount of noncash consideration that may be considered cash pursuant to certain permitted dispositions. The ABL Credit Facility has a borrowing base of the sum of 85% to 90% of monthly eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the borrowing base), in each case, depending on the credit ratings of our accounts receivable counterparties, less customary reserves (the “Borrowing Base”) as redetermined monthly. The Borrowing Base as of December 31, 2024, was approximately $164.1 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) $15.0 million. Under the ABL Credit Facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens or indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.
Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either the Secured Overnight Financing Rate (“SOFR”) or the base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for SOFR loans and 0.75% to 1.25% for base rate loans. The weighted average annual interest rate for our ABL Credit Facility for the year ended December 31, 2024, was 7.12%.
The loan origination costs relating to the ABL Credit Facility are classified as an asset on our balance sheet. As of December 31, 2024, and 2023, we had outstanding borrowings under our ABL Credit Facility of $45.0 million and $45.0 million, respectively.
We entered into a contractual arrangement with an equipment manufacturer to purchase mobile natural gas-fueled power generation equipment for our PROPWR business line, with a total cost of $122.0 million, of which approximately $103.7 million, representing progress payments beyond the initial down payment on this equipment, will be financed. We currently expect to start receiving this equipment from the end of the second quarter of 2025 through early 2026.
Off Balance Sheet Arrangements
We had no material off balance sheet arrangements as of December 31, 2024.
Capital Requirements, Future Sources and Use of Cash
Capital expenditures incurred were $133.4 million during the year ended December 31, 2024, as compared to $310.0 million during the year ended December 31, 2023. The significant portion of our total capital expenditures incurred during the year ended December 31, 2024, were maintenance capital expenditures and conversion of our hydraulic fracturing equipment to lower emissions equipment.
Our future material use of cash will be to fund our capital expenditures. Capital expenditures for 2025 are projected to be primarily related to capital expenditures to extend the useful life of our existing completion services assets, costs to convert some existing equipment to lower emissions equipment, purchase power generation 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 2025, we expect our capital expenditures to range between $300 million to $400 million which includes approximately $150 million to $200 million for our completion services business and approximately $150 million to $200 million for our PROPWR business. We entered into a contractual arrangement with an equipment manufacturer to purchase mobile natural gas-fueled power generation equipment for our PROPWR business line, with a total cost of $122.0 million, of which approximately $103.7 million will be financed, representing progress payments beyond the initial down payment on this equipment. We currently expect receive this equipment beginning with the end of the second quarter of 2025 through early 2026. We entered into a contractual arrangement with another related equipment manufacturer to purchase additional natural gas-fueled power generation equipment for our PROPWR business line, with a total cost of $25.0 million. We currently expect to receive this equipment in the first half of 2025. We could incur significant additional capital expenditures if our projected activity levels increase during the course of the year, inflation and supply chain tightness continues to adversely impact our operations or we invest in new or different lower emissions equipment. The Company will continue to evaluate the emissions profile of its equipment over the coming years and may, depending on market conditions, convert or retire additional conventional Tier II equipment in favor of lower emissions equipment. The Company’s decisions regarding the retirement or conversion of equipment or the addition of lower emissions equipment will be subject to a number of factors, including (among other factors) the availability of equipment, including parts and major components, supply chain disruptions, prevailing and expected commodity prices, customer demand and requirements and the Company’s evaluation of projected returns on conversion or other capital expenditures. Depending on the impact of these factors, the Company may decide to retain conventional equipment for a longer period of time or accelerate the retirement, replacement or conversion of that equipment.
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.
Contractual Obligations
The following table presents our contractual obligations and other commitments as of December 31, 2024:
(in thousands)
Period
Total 1 year or less More than 1 year
ABL Credit Facility (1)
$ 45,000 $ - $ 45,000
Operating leases (2)(3)
126,550 51,238 75,312
Finance lease (4)
34,377 20,915 13,462
Sand commitments (5)
1,500 1,500 -
Equipment purchase commitments (6)
147,000 120,160 26,840
Par Five deferred cash consideration (7)
3,109 3,109 -
AquaProp deferred cash consideration (8)
3,664 3,664 -
Total $ 361,200 $ 200,586 $ 160,614
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(1)Exclusive of future commitment fees, amortization of deferred financing costs, interest expense or other fees on our ABL Credit Facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments of future interest rates to be changed. However, assuming a weighted average interest rate of 7.12%, and that our ABL Credit Facility debt balance remains the same, our estimated annual interest payment will be $3.2 million.
(2)Operating leases exclude short-term leases and other commitments (see Note 17. Leases and Note 18. Commitments and Contingencies in the financial statements for additional disclosures).
(3)Includes our leases for FORCE® electric-powered hydraulic fracturing fleets (312,000 HHP). We expect to receive the remaining equipment under these leases in the first half of 2025.
(4)Finance lease for certain power generation equipment (70 MW) to support electric-powered hydraulic fracturing equipment.
(5)Relates to a take-or-pay sand commitment with one of our sand vendors.
(6)Represents contractual commitments with two equipment manufacturers to purchase 140 megawatts of mobile natural gas-fueled power generation equipment for our PROPWR business line (see Note 18. Commitments and Contingencies in the financial statements for additional disclosures).
(7)Represents the unpaid portion of the purchase consideration on our acquisition of Par Five to be used to cover (i) the amount by which the estimated purchase price exceeds the final purchase price, if any, and (ii) any indemnity obligations of the seller, if any.
(8)Represents the unpaid portion of the purchase consideration on our acquisition of AquaProp to be used to cover (i) the amount by which the estimated purchase price exceeds the final purchase price, if any, and (ii) any indemnity obligations of the seller, if any.
We enter into other purchase agreements with Sand Suppliers to secure the supply of sand in the normal course of our business. The agreements with the Sand Suppliers require that we purchase a minimum volume of sand, based primarily on a certain percentage of our sand requirements from our customers or in certain situations based on predetermined fixed minimum volumes, otherwise certain penalties (shortfall fees) may be charged. The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the minimum volumes or a fixed price per ton of unpurchased volumes. Our 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 GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the years. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.
Listed below are the accounting 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.
Business Combinations
Business combinations are accounted for under the acquisition method of accounting. Under this method, the assets acquired and liabilities assumed are recognized at their respective fair values as of the date of acquisition. The excess, if any, of the acquisition price over the fair values of the assets acquired and liabilities assumed is recorded as goodwill if the definition of a business is met. For significant acquisitions, we utilize third-party appraisal firms to assist us in determining the fair values for certain assets acquired and liabilities assumed using discounted cash flows and other applicable valuation techniques. We record any acquisition related costs as expenses when incurred.
Adjustments to the fair values of assets acquired and liabilities assumed are made until we obtain all relevant information regarding the facts and circumstances that existed as of the acquisition date (the “measurement period”), not to exceed one year from the date of the acquisition. We recognize measurement period adjustments in the period in which we determine the amounts, including the effect on earnings of any amounts we would have recorded in previous periods if the accounting had been completed at the acquisition date.
The estimation of the fair values of assets and liabilities acquired in business combinations requires significant judgment. Our fair value estimates require us to use significant observable and unobservable inputs. 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. A significant change in the observable and unobservable inputs and determination of fair value of the assets and liabilities acquired could significantly impact our consolidated financial statements.
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 retire certain components of equipment such as fluid ends and power ends, rather than the entire pieces of equipment. The associated loss is recorded in our statement of operations as part of net loss on disposal of assets and businesses, which was $7.5 million, $73.0 million, and $102.1 million for the years ended December 31, 2024, 2023, and 2022, respectively.
The estimated useful lives and salvage values of property and equipment are 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 $18.5 million impact on pre-tax loss during the year ended December 31, 2024. 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 - 22 years
Leasehold improvements
5 - 20 years
Impairment of Long-Lived Assets
In accordance with the Financial Accounting Standards Board Accounting Standards Codification (“ASC”) 360 regarding Accounting for the Impairment or Disposal of Long-Lived Assets, we review the long-lived assets including intangible assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable to the assets is less than the carrying amount of such assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset. Our cash flow forecasts require us to make certain judgments regarding long-term forecasts of future revenue and costs and cash flows related to the assets subject to review. The significant assumption in our cash flow forecasts is our estimated equipment utilization and profitability. The significant assumption is uncertain in that it is driven by future demand for our services and utilization, which could be impacted by crude oil market prices, future market conditions and technological advancements. Our fair value estimates for certain long-lived assets require us to use significant other observable inputs, including assumptions related to market based on recent auction sales or selling prices of comparable equipment. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future.
If the crude oil market declines or the demand for our services does not recover, and if our equipment remains idle or underutilized, the estimated fair value of such equipment may decline, which could result in future impairment charges. Though the impacts of variations in any of these factors can have compounding or offsetting impacts, a 10% decline in the estimated future cash flows of our existing asset groups will not indicate an impairment.
During the year ended December 31, 2024, we recorded property and equipment impairment expense of approximately $188.6 million in connection with our conventional Tier II diesel-only hydraulic fracturing pumping units and associated conventional assets. In 2022, we recorded property and equipment impairment expense of $57.5 million on our DuraStim® electric-powered hydraulic fracturing equipment within the hydraulic fracturing operating segment.
Intangible assets consist of trademark/trade name, customer relationships and favorable contracts. Trademark/trade names are amortized on a straight-line basis over useful lives of ten and fifteen years. Customer relationships are amortized on a straight-line basis over useful lives of six and ten years. Favorable contracts are amortized on a straight-line basis over useful lives of thirty months and five years. Internally developed software will be amortized on a straight-line basis over a useful life of twenty-nine months. Our estimated useful life could be sensitive to changes in market conditions and management’s judgment, and are likely to change in the future if certain events occur. Presently, there are no events or circumstances that will cause us to believe that our estimated useful life for our intangible assets are likely to change.
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 and intangible assets as of December 31, or more frequently if circumstances indicate that impairment may exist.
In connection with the AquaProp Acquisition, we added $0.9 million of goodwill in our hydraulic fracturing operating segment during the year ended December 31, 2024. We recorded goodwill impairment expense of $23.6 million in our wireline reporting unit during the year ended December 31, 2024. There were no additions to goodwill during the year ended December 31, 2023. The hydraulic fracturing operating segment was the only segment with goodwill at December 31, 2024. The wireline operating segment was the only segment with goodwill at December 31, 2023. There were no goodwill impairment losses during the year ended December 31, 2023. We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles-Goodwill and Other, on December 31, 2024, at which time, we determined that the fair value of our wireline reporting unit was substantially in excess of its carrying value resulting in impairment. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted equipment utilization, pricing and cost assumptions. Our discounted cash flow analysis includes significant assumptions regarding discount rates, utilization, expected profitability margin, forecasted maintenance capital expenditures, and the timing of expected cash flow. As such, our goodwill analysis incorporates inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecast. As of December 31, 2024, and 2023, our goodwill carrying value was $0.9 million and $23.6 million, respectively.
Leases
In accordance with ASC Topic 842, the Company determines if a contract is a lease at inception and evaluates identified leases for operating and finance lease accounting. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The Company uses a discount rate based on its estimated incremental borrowing rate on a collateralized basis with similar terms and economic considerations as its lease payments at the lease commencement in determining the present value of lease payments. Lease terms may include options to renew the lease or purchase the underlying assets, however, the Company typically cannot determine its intent to renew the lease or purchase the assets with reasonable certainty at inception. The Company elected the short-term lease recognition practical expedient provided by ASC 842 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. We elected to analogize to the measurement guidance of ASC 360 to capitalize costs incurred to place a leased asset into its intended use and to present such capitalized costs as part of the related lease right-of-use asset cost as initial direct costs.
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, 2024, 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 2024.
Commodity Price Risk
Our materials and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our completion services such as proppants, perforating guns, 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 decrease/(increase) in pre-tax income/(loss) of approximately $0.5 million, $0.5 million, and $0.1 million, for the years ended December 31, 2024, 2023, and 2022, 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.
FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm (PCAOB ID: 49)
Report of Independent Registered Public Accounting Firm (PCAOB ID: 34)
Consolidated Balance Sheets as of December 31, 2024 and 2023
Consolidated Statements of Operations for the years ended December 31, 2024, 2023 and 2022
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2024, 2023 and 2022
Consolidated Statements of Cash Flows for the years ended December 31, 2024, 2023 and 2022
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of ProPetro Holding Corp.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of ProPetro Holding Corp. and its subsidiaries (the Company) as of December 31, 2024 and 2023, the related consolidated statements of operations, shareholders' equity and cash flows for each of the two years in the period ended December 31, 2024, and the related notes to the consolidated financial statements (collectively, the financial statements). In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024, 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, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013, and our report dated February 20, 2025, expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
As discussed in Notes 2 and 11 to the financial statements, the Company adopted ASU 2023-07, Segment Reporting (Topic 280) as of December 31, 2024, and changed the composition of its segment information in 2023. We also have audited the adjustments necessary to restate the 2022 segment information and to reflect the adoption of ASU 2023-07, Segment Reporting (Topic 280) to the 2022 segment information, as provided in Note 11. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review or apply any procedures to the 2022 financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2022 financial statements taken as a whole.
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 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 Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Business Combination-Aqua Prop, LLC
As discussed in Note 4 of the consolidated financial statements, the Company completed the acquisition of all of the outstanding equity interests in Aqua Prop LLC (AquaProp) on May 31, 2024, for total consideration transferred of $35.8 million, which included contingent consideration with an acquisition date fair value of $10.9 million. The Company accounted for this transaction under the acquisition method of accounting for business combinations whereby the fair value of the consideration transferred was allocated to the assets acquired, including a customer relationship intangible asset of $18.6 million, and liabilities assumed based upon their acquisition date fair values. Management estimated the fair value of the contingent consideration by applying a probability-weighted expected return method for the different scenarios that may occur based upon the amount of additional equipment delivered by the seller, at the request of the Company, and the amount of wet sand expected to be delivered by such equipment within a 30-month period. Management estimated the fair value of the customer relationship intangible asset using a discounted cash flow method whereby forecasted cash flows expected to be derived from the intangible asset over the economic life of the asset, adjusted for expected attrition, are discounted to present value.
We identified the valuation of the customer relationship intangible asset and the contingent consideration liability at the AquaProp acquisition date as a critical audit matter because of the significant assumptions management used in estimating the fair values, including forecasted cash flows and the selection of a discount rate for the customer relationship intangible asset and forecasted tonnage of wet sand expected to be delivered for the contingent consideration. Auditing management’s assumptions involved a high degree of auditor judgment and an increase in audit effort, including the use of valuation specialists, due to the impact these assumptions could have on the accounting estimates.
Our audit procedures related to the valuation of the customer relationship intangible asset and the contingent consideration liability included the following, among others:
•We obtained an understanding of the relevant controls related to management’s business combination fair value estimates and tested such controls for design and operating effectiveness, including controls over management’s review of significant assumptions used in the fair value estimates.
•We read the purchase and sale agreement to understand and evaluate the terms of the acquisition.
•We tested the reasonableness of management’s forecasts of cash flows in the valuation of the customer relationship intangible asset by comparing them to historical results and evaluating publicly available industry information.
•We tested the reasonableness of management’s forecasts of tonnage of wet sand to be delivered by comparing the estimated capacity of each piece of equipment to in-process contracts and considering the impact of the estimated timing of the delivery to the estimate of fair value.
•We utilized our valuation specialists to assist in the following procedures, among others:
◦Evaluating the appropriateness of the valuation models used by management to estimate the fair values of the customer relationship intangible asset and contingent consideration and testing their mathematical accuracy.
◦Evaluating the appropriateness of the methodology used by management to develop the attrition rate for the customer relationship.
◦Comparing the source information underlying the determination of the discount rates to publicly available market data and verifying the accuracy of the calculations.
Impairment of Long-lived Assets-Fair Value of Conventional Tier II Diesel-only Hydraulic Fracturing Pumping Units and Associated Conventional Assets
As discussed in Notes 2 and 5 to the consolidated financial statements, at September 30, 2024, the Company performed a recoverability assessment on the long-lived assets in its conventional Tier II diesel-only hydraulic fracturing pumping units and associated conventional assets asset group (the “Tier II Units”). In performing the recoverability assessment, the Company first compared the carrying value of the asset group to the estimated undiscounted cash flows to be generated over the remaining useful life of the asset group’s primary asset. Because the carrying value of the asset group exceeded the estimated undiscounted cash flows, the Company then estimated the fair value of the asset group, utilizing both a market approach and a cost approach, and recorded an impairment charge of $188.6 million.
We identified management’s estimated fair value of the Tier II Units as a critical audit matter because of the significant assumptions management used in estimating the fair value of the assets, including the selection of the valuation methods used to estimate fair value, the determination of the highest and best use of the assets, and consideration of the appropriateness of market data, among others. Auditing management’s assumptions involved a high degree of auditor judgment and an increase in audit effort, including the use of our valuation specialists, due to the impact these assumptions could have on the accounting estimate.
Our audit procedures related to the Company’s estimate of the fair value of the Tier II Units included the following, among others:
•We obtained an understanding of the relevant controls related to management’s estimate of fair value of the Tier II Units and tested such controls for design and operating effectiveness, including controls over management’s review of the significant assumptions used in estimating the fair value of the underlying assets.
•We tested the completeness and accuracy of the Tier II Units by agreeing the carrying values and other relevant information to the underlying support.
•We utilized our valuation specialists to assist in the following procedures, among others:
◦Evaluating the appropriateness of the valuation models used by management to estimate the fair value of the Tier II Units and testing their mathematical accuracy.
◦Evaluating management’s determination of the highest and best use of the Tier II Units.
◦Corroborating managements estimates of fair value by comparing such estimates to publicly available market data.
Goodwill Impairment Testing-Wireline Reporting Unit
As discussed in Notes 2 and 5 to the consolidated financial statements, management tests the Company’s goodwill for impairment, at the reporting unit level, at December 31 of each fiscal year, or more frequently if events or changes in circumstances indicate the goodwill might be impaired. To test goodwill for impairment, management compares the estimated fair value of the reporting unit to the carrying amount, including the recorded goodwill. An impairment is recorded when the carrying value of the reporting unit exceeds its estimated fair value. The Company's estimated reporting unit fair value is based on a combination of income and market approaches. 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. During the year ended December 31, 2024, the Company recorded a goodwill impairment charge of $23.6 million in its Wireline reporting unit, which represented a full impairment of the goodwill in that reporting unit.
We identified the valuation of the Wireline reporting unit as a critical audit matter because of the significant assumptions management used in estimating the fair value of the reporting unit, including revenue growth rates and margin percentages used in the projected cash flows, the determination of the discount rate applicable to the reporting unit, and the identification of comparable guideline public companies and market multiples. Auditing management’s assumptions involved a high degree of auditor judgment and an increase in audit effort, including the use of valuation specialists, due to the impact these assumptions could have on the estimate of fair value.
Our audit procedures related to the estimated fair value of the Wireline reporting unit included the following, among others:
•We obtained an understanding of the relevant controls related to management’s impairment assessment and tested such controls for design and operating effectiveness, including controls over management’s review of the significant assumptions utilized in the fair value measurement.
•We tested the reasonableness of management’s forecasts of cash flows, including revenue and margins, by comparing them to historical results and evaluating publicly available industry information.
•We tested the underlying data used by management in the development of the forecasts of cash flows for accuracy and completeness by agreeing it to source data.
•We utilized our valuation specialists to assist in the following procedures, among others:
◦Evaluating the appropriateness of the Company's valuation methodology and testing the mathematical accuracy.
◦Testing the reasonableness of the discount rate using in the income approach by comparing the inputs used by management to publicly available market data.
◦Evaluating the comparability of the guideline public companies identified by management based upon publicly available market data.
◦Corroborating the market multiples selected by the Company in the market approach by comparing them publicly available market data.
/s/ RSM US LLP
RSM US LLP
We have served as the Company's auditor since 2023.
Houston, Texas
February 20, 2025
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of ProPetro Holding Corp.
Opinion on Internal Control over Financial Reporting
We have audited ProPetro Holding Corp.'s (the Company) internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements of the Company and our report dated February 20, 2025 expressed an unqualified opinion.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Aqua Prop, LLC from its assessment of internal control over financial reporting as of December 31, 2024, because it was acquired by the Company in a purchase business combination in the second quarter of 2024. We have also excluded Aqua Prop, LLC from our audit of internal control over financial reporting. Aqua Prop, LLC is a wholly owned subsidiary whose total assets and revenue represent approximately 4.9% and 3.1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2024.
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 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 U.S. 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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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/ RSM US LLP
RSM US LLP
Houston, Texas
February 20, 2025
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
ProPetro Holding Corp. and Subsidiaries
Opinion on the Financial Statements
We have audited, before the effects of the retrospective adjustments to the disclosures for a change in the composition of reportable segments and the adoption of ASU No. 2023-07, Segment Reporting, discussed in Note 11 to the consolidated financial statements, the consolidated statements of operations, shareholders' equity, and cash flows of ProPetro Holding Corp. and Subsidiaries (the “Company”), for the year ended December 31, 2022, and the related notes (collectively, referred to as, the “financial statements”) (the 2022 financial statements before the effects of the retrospective adjustments discussed in Note 11 to the financial statements are not presented herein). In our opinion, the 2022 financial statements, before the effects of the retrospective adjustments to the disclosures for a change in the composition of reportable segments and the adoption of ASU No. 2023-07, Segment Reporting, discussed in Note 11 to the financial statements, present fairly, in all material respects, the results of the Company’s operations and cash flows for the year ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.
We were not engaged to audit, review, or apply any procedures to the retrospective adjustments to the disclosures for a change in the composition of reportable segments and the adoption of ASU No. 2023-07, Segment Reporting discussed in Note 11 to the financial statements, and accordingly, we do not express an opinion or any other form of assurance about whether such retrospective adjustments are appropriate and have been properly applied. Those retrospective adjustments were audited by other auditors.
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 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 U.S. 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 the financial statements are free of material misstatement, whether due to error or fraud. Our audit 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 audit 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 audit provided a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 23, 2023
We began serving as the Company's auditor since 2013. In 2023, we became the predecessor auditor.
PROPETRO HOLDING CORP.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2024 AND 2023
(In thousands, except share data)
2024 2023
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 50,443 $ 33,354
Accounts receivable - net of allowance for credit losses of $0 and $236, respectively
195,994 237,012
Inventories 16,162 17,705
Prepaid expenses 17,719 14,640
Short-term investment, net 7,849 7,745
Other current assets
4,054 353
Total current assets
292,221 310,809
PROPERTY AND EQUIPMENT - net of accumulated depreciation
688,225 967,116
OPERATING LEASE RIGHT-OF-USE ASSETS 132,294 78,583
FINANCE LEASE RIGHT-OF-USE ASSETS 30,713 47,449
OTHER NONCURRENT ASSETS:
Goodwill 920 23,624
Intangible assets - net of amortization 64,905 50,615
Other noncurrent assets
14,367 2,116
Total other noncurrent assets
80,192 76,355
TOTAL ASSETS
$ 1,223,645 $ 1,480,312
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable $ 92,963 $ 161,441
Accrued and other current liabilities 70,923 75,616
Operating lease liabilities 39,063 17,029
Finance lease liabilities 19,317 17,063
Total current liabilities 222,266 271,149
DEFERRED INCOME TAXES 59,770 93,105
LONG-TERM DEBT 45,000 45,000
NONCURRENT OPERATING LEASE LIABILITIES
58,849 38,600
NONCURRENT FINANCE LEASE LIABILITIES
13,187 30,886
OTHER LONG-TERM LIABILITIES
8,300 3,180
Total liabilities
407,372 481,920
COMMITMENTS AND CONTINGENCIES (Note 18)
SHAREHOLDERS’ EQUITY:
Preferred stock, $0.001 par value, 30,000,000 shares authorized, none issued, respectively
- -
Common stock, $0.001 par value, 200,000,000 shares authorized, 102,994,958 and 109,483,281 shares issued and outstanding, respectively
103 109
Additional paid-in capital 884,995 929,249
Retained earnings (accumulated deficit)
(68,825) 69,034
Total shareholders’ equity
816,273 998,392
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$ 1,223,645 $ 1,480,312
See notes to consolidated financial statements.
PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2024, 2023 AND 2022
(In thousands, except per share data)
2024 2023 2022
REVENUE - Service revenue
$ 1,444,286 $ 1,630,399 $ 1,279,701
COSTS AND EXPENSES:
Cost of services (exclusive of depreciation and amortization) 1,065,514 1,131,801 882,820
General and administrative expenses (inclusive of stock-based compensation) 114,323 114,354 111,760
Depreciation and amortization 211,733 180,886 128,108
Property and equipment impairment expense 188,601 - 57,454
Goodwill impairment expense 23,624 - -
Loss on disposal of assets and businesses, net
7,451 73,015 102,150
Total costs and expenses
1,611,246 1,500,056 1,282,292
OPERATING (LOSS) INCOME
(166,960) 130,343 (2,591)
OTHER (EXPENSE) INCOME:
Interest expense (7,815) (5,308) (1,605)
Other income (expense), net
5,531 (9,533) 11,582
Total other income (expense)
(2,284) (14,841) 9,977
INCOME (LOSS) BEFORE INCOME TAXES (169,244) 115,502 7,386
INCOME TAX BENEFIT (EXPENSE)
31,385 (29,868) (5,356)
NET (LOSS) INCOME
$ (137,859) $ 85,634 $ 2,030
NET (LOSS) INCOME PER COMMON SHARE:
Basic
$ (1.31) $ 0.76 $ 0.02
Diluted
$ (1.31) $ 0.76 $ 0.02
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic
105,469 113,004 105,868
Diluted
105,469 113,416 106,939
See notes to consolidated financial statements.
PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2024, 2023 AND 2022
(In thousands)
Common Stock
Shares Amount Additional
Paid-In
Capital Retained Earnings (Accumulated
Deficit) Total
BALANCE - January 1, 2022 103,437 $ 104 $ 844,828 $ (18,630) $ 826,302
Stock-based compensation cost - - 21,881 - 21,881
Issuance of equity award-net 11,078 10 107,689 - 107,699
Tax withholdings paid for net settlement of equity awards - - (3,879) - (3,879)
Net income - - - 2,030 2,030
BALANCE - December 31, 2022 114,515 $ 114 $ 970,519 $ (16,600) $ 954,033
Stock-based compensation cost - - 14,450 - 14,450
Issuance of equity awards-net 763 1 (1) - -
Tax withholdings paid for net settlement of equity awards - - (3,543) - (3,543)
Share repurchases (5,795) (6) (51,732) - (51,738)
Excise tax on share repurchases - - (444) - (444)
Net income - - - 85,634 85,634
BALANCE - December 31, 2023 109,483 $ 109 $ 929,249 $ 69,034 $ 998,392
Stock-based compensation cost - - 17,288 - 17,288
Issuance of equity-net 707 1 (1) - -
Tax withholdings paid for net settlement of equity awards - - (1,909) - (1,909)
Share repurchases (7,195) (7) (59,101) - (59,108)
Excise tax on share repurchases - - (531) - (531)
Net loss - - - (137,859) (137,859)
BALANCE - December 31, 2024 102,995 $ 103 $ 884,995 $ (68,825) $ 816,273
See notes to consolidated financial statements.
PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2024, 2023 AND 2022
(In thousands)
2024 2023 2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income $ (137,859) $ 85,634 $ 2,030
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization 211,733 180,886 128,108
Property and equipment impairment expense 188,601 - 57,454
Goodwill impairment expense 23,624 - -
Deferred income tax (benefit) expense (33,336) 27,840 4,213
Amortization of deferred debt issuance costs 438 359 785
Stock-based compensation 17,288 14,450 21,881
Provision for credit losses - 34 202
Loss on disposal of assets and businesses, net 7,451 73,015 102,150
Unrealized (gain) loss on short-term investment (105) 2,538 1,570
Business acquisition contingent consideration adjustments (2,600) - -
Noncash income from settlement with equipment manufacturer - - (2,668)
Changes in operating assets and liabilities:
Accounts receivable 51,498 (12,408) (66,900)
Other current assets (2,301) (831) 354
Inventories 1,543 (6,017) 124
Prepaid expenses 1,327 (6,143) 743
Accounts payable (64,501) (11,429) 27,428
Accrued and other current liabilities (10,506) 26,814 22,955
Net cash provided by operating activities
252,295 374,742 300,429
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (140,297) (370,869) (319,683)
Business acquisitions, net of cash acquired (21,038) (22,215) (38,639)
Proceeds from sale of assets
6,236 8,957 8,577
Net cash used in investing activities
(155,099) (384,127) (349,745)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings - 30,000 30,000
Repayments of borrowings - (15,000) -
Payments of finance lease obligation (17,676) (4,663) -
Repayments of insurance financing (970) - -
Payment of debt issuance costs - (1,179) (824)
Proceeds from exercise of equity awards - - 963
Tax withholdings paid for net settlement of equity awards (1,909) (3,543) (3,879)
Share repurchases (59,108) (51,738) -
Payment of excise taxes on share repurchases (444) - -
Net cash used in financing activities
(80,107) (46,123) 26,260
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH 17,089 (55,508) (23,056)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - Beginning of year
33,354 88,862 111,918
CASH, CASH EQUIVALENTS AND RESTRICTED CASH - End of year
$ 50,443 $ 33,354 $ 88,862
See notes to consolidated financial statements.
PROPETRO HOLDING CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
FOR THE YEARS ENDED DECEMBER 31, 2024, 2023 AND 2022
(In thousands)
The following table provides a reconciliation of cash, cash equivalents and restricted cash to amounts reported within the consolidated balance sheets:
2024 2023 2022
Summary of cash, cash equivalents and restricted cash
Cash and cash equivalents $ 50,443 $ 33,354 $ 78,862
Restricted cash - - 10,000
Total cash, cash equivalents and restricted cash - End of year $ 50,443 $ 33,354 $ 88,862
See notes to consolidated financial statements.
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, and it is a holding company for its wholly owned subsidiaries ProPetro Services, Inc., a Texas corporation (“Services”), Silvertip Completion Services Operating, LLC, a Delaware limited liability company (“Silvertip”), Aqua Prop, LLC, a Texas limited liability company (“AquaProp”) and ProPetro Energy Solutions, LLC, a Texas limited liability company (“PROPWR”). Services, Silvertip and AquaProp together offer hydraulic fracturing, wireline, cementing, wet sand solutions and other complementary services to oil and gas producers, located primarily in Texas and New Mexico. PROPWR has not begun any revenue-generating activities yet and was formed to provide power generation services to oil and gas producers and non-oil and gas applications such as general industrial projects and data centers, located primarily in Texas and New Mexico and will do business as PROPWR. Holding was converted and incorporated as 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 Holding, Services, Silvertip, AquaProp, and PROPWR.
On November 1, 2024, we sold our cementing business located in Vernal, Utah, to Big 4 Services LLC, a Wyoming limited liability company (“Big 4”), solely owned by a former employee as part of a strategic repositioning. We received a promissory note for $13.0 million as consideration. The note receivable is secured by substantially all assets of Big 4 and the former employee’s ownership interests in and distributions from Big 4. The note receivable is to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025 to December 31, 2029. We recorded a gain on disposal of $8.2 million related to the sale of the business within loss on disposal of assets and business within our consolidated statement of operations for the year ended December 31, 2024. The former employee was part of our cementing operations until November 1, 2024 and is no longer affiliated with the Company. The Company does not expect to have any significant continuing involvement with Big 4 other than collection of the note receivable.
On May 31, 2024, we consummated the acquisition of all of the outstanding equity interests in AquaProp, which provides wet sand solutions for hydraulic fracturing sand requirements at oil well sites (the “AquaProp Acquisition”). The cash consideration for the AquaProp Acquisition includes $13.7 million paid to the seller, $7.2 million paid to settle the seller’s outstanding debt, and $0.3 million paid for the seller’s transaction expenses. As a result of the acquisition, we expanded our operations into the wet sand service business unit.
On April 22, 2024, we entered into a sub-agreement for hydraulic fracturing services with XTO Energy Inc. ("XTO"), a wholly owned subsidiary of ExxonMobil, pursuant to which we will provide hydraulic fracturing, wireline and pumpdown services with two committed FORCE® electric-powered hydraulic fracturing fleets with the option to add a third FORCE® fleet (also with wireline and pumpdown services) for a period of three years or for contracted hours, whichever occurs last, with respect to each fleet, subject to certain termination and release rights.
On December 1, 2023, we consummated the purchase of the assets and operations of Par Five Energy Services LLC (“Par Five”), which provides cementing services in the Delaware Basin in exchange for $25.3 million of cash including deferred cash consideration of $3.1 million which is payable to Par Five or its beneficiary on June 1, 2025, with interest at 4.0% per annum (the “Par Five Acquisition”). Par Five’s business complements our existing cementing business and enables us to serve both the Midland and Delaware sub-basins of the Permian Basin.
On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip, which provides wireline perforation and ancillary services solely in the Permian Basin in exchange for 10.1 million shares of our common stock valued at $106.7 million, $30.0 million of cash, the payoff of $7.2 million of assumed debt, and the payment of certain other closing and transaction costs (“the Silvertip Acquisition”).
On December 31, 2018, we consummated the purchase of certain pressure pumping assets and real property from Pioneer Natural Resources USA, Inc. (“Pioneer”) and Pioneer Pumping Services, LLC (“Pioneer Pumping Services”) (the “Pioneer Pressure Pumping Acquisition”). In connection with the Pioneer Pressure Pumping Acquisition, Pioneer received 16.6 million shares of our common stock and $110.0 million in cash. In May 2024, Pioneer merged with and into a wholly owned subsidiary of Exxon Mobil Corporation (“ExxonMobil”) after which ExxonMobil became the owner of these shares. The Company currently provides pressure pumping, wireline and other services to ExxonMobil and previously provided such services to Pioneer.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 subsidiaries, Services, Silvertip, AquaProp, and PROPWR. 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, intangible assets, discount rates underlying our lease right-of-use assets and liabilities, 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.
Hydraulic fracturing is an oil well completion technique, which is part of the overall well completions process. It 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 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.
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.
Wet sand solutions, which is part of our hydraulic fracturing operating segment, involve providing onsite storage and handling of wet sand used in the completion phase of shale wellbores. We recognize revenue from sale of wet sand, location services and transportation services over time using a progress output, unit-of-work performed method, which is based on the agreed fixed transaction price, fixed units per stage and actual stages completed.
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.
Wireline services (including pumpdown) are oil well completion techniques, which are part of the well completion services. Our wireline services utilize equipment with a drum of wireline to deploy perforating guns in the well to perforate the casing, cement, and formation. Once the well is perforated, the well can be fractured. Pumpdown utilizes pressure pumping equipment to pump water into the well to deploy perforating guns attached to wireline through the lateral section of a well. Our wireline contracts with our customers have one 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
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
recognizing revenue based on actual stages completed faithfully depicts how our wireline services are transferred to our customers over time. In addition, certain of our wireline equipment is entitled to daily equipment charges while the equipment is on the customer’s locations. The Company recognizes revenue related daily equipment charges on a daily basis as the performance obligations are met.
The transaction price for each performance obligation for all our completion services is fixed per our contracts with our customers.
Coiled tubing involves complementary downhole well completion/remedial services. The performance obligation for these services had a fixed transaction price which was satisfied at a point-in-time upon completion of the service when control was transferred to the customer. Accordingly, we recognized revenue at a point-in-time, upon completion of the service and transfer of control to the customer. Effective September 1, 2022, we shut down our coiled tubing operations, and disposed of all of our coiled tubing assets.
The Company assesses customers’ ability and intention to pay, which is based on a variety of factors including historical payment experience and financial condition. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 60 days.
Business Combinations - Business combinations are accounted for under the acquisition method of accounting. Under this method, the assets acquired and liabilities assumed are recognized at their respective fair values as of the date of acquisition. The excess, if any, of the acquisition price over the fair values of the assets acquired and liabilities assumed is recorded as goodwill if the definition of a business is met. For significant acquisitions, we utilize third-party appraisal firms to assist us in determining the fair values for certain assets acquired and liabilities assumed using discounted cash flows and other applicable valuation techniques. We record any acquisition related costs as expenses when incurred.
Adjustments to the fair values of assets acquired and liabilities assumed are made until we obtain all relevant information regarding the facts and circumstances that existed as of the acquisition date (the “measurement period”), not to exceed one year from the date of the acquisition. We recognize measurement period adjustments in the period in which we determine the amounts, including the effect on earnings of any amounts we would have recorded in previous periods if the accounting had been completed at the acquisition date.
The estimation of the fair values of assets and liabilities acquired in business combinations requires significant judgment. Our fair value estimates require us to use significant observable and unobservable inputs. 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. A significant change in the observable and unobservable inputs and determination of fair value of the assets and liabilities acquired could significantly impact our consolidated financial statements.
Cash and Cash Equivalents - All highly liquid investments with an original maturity of three months or less.
Restricted Cash - Our restricted cash related to cash received from a customer in connection with our contract with the customer to provide FORCE® electric-powered hydraulic fracturing equipment and services. The restricted cash was used to pay for contractually agreed upon expenditures. Our restricted cash balances at December 31, 2024 and 2023 were $0 and $0, respectively.
Accounts Receivable - Accounts receivable are stated at the amount billed and billable to customers. At December 31, 2024, December 31, 2023 and January 1, 2023, amounts billed to customers (net of allowance for credit losses) included as part of our accounts receivable was $148.8 million, $181.6 million, and $164.0 million, respectively. At December 31, 2024, December 31, 2023, and January 1, 2023, accrued revenue (unbilled receivable) included as part of our accounts receivable was $47.2 million, $55.4 million and $51.9 million, respectively. At December 31, 2024, the transaction price allocated to the remaining performance obligation for our partially completed hydraulic fracturing and wireline operations was $38.7 million, which is expected to be completed and recognized within one month following the current period balance sheet date. At December 31, 2023, the transaction price allocated to the remaining performance obligation for our then partially completed hydraulic fracturing and wireline operations was $33.8 million, which was recorded as part of revenues for the year ended December 31, 2024.
As of December 31, 2024, the Company had no 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
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
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 depressed economic activities, 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.
The table below shows a summary of allowance for credit losses:
(in thousands)
Year Ended December 31,
2024 2023 2022
Balance - January 1, $ 236 $ 419 $ 217
Provision for credit losses during the period - 34 202
Write-off during the period (236) (217) -
Balance - December 31, $ - $ 236 $ 419
Contract Assets and Liabilities - We do not have any significant contract asset balances other than amounts billed to customers and accrued revenue discussed in the Accounts Receivable section above. Contract liabilities include cash advances from a customer in connection with our contract with the customer to provide FORCE® electric-powered hydraulic fracturing equipment and services. These cash advances from the customer will be credited towards the customer’s invoice as our revenue performance obligations are met over the contract period. The cash advances received represent contract liabilities in connection with the performance of certain completion services. The cash advance (contract liability) balances, which are included in accrued and other current liabilities in our consolidated balance sheets, were $11.8 million, $19.2 million, and $10.0 million at December 31, 2024, December 31, 2023, and January 1, 2023, respectively. During the years ended December 31, 2024 and 2023, we recognized revenue of $6.7 million, and $5.7 million, respectively, from the cash advance amount outstanding at the beginning of the period.
Inventories - Inventories, which consists only of raw materials and fluid ends, are stated at lower of average cost and net realizable value.
Note Receivable - Note receivable is stated at face value plus accrued interest and represents the consideration received for sale of our cementing business located in Vernal, Utah, to a business owned by a former employee and is secured by substantially all assets of the former employee’s business and the former employee’s ownership interests in and distributions from the business. The note receivable is to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025, to December 31, 2029. At December 31, 2024, the note receivable had a carrying amount of $13.2 million including accrued interest, which the Company expects to be fully collectible. Of the carrying amount at December 31, 2024, the amount collectible within one year was $2.1 million and the amount collectible beyond one year was $11.1 million, which are included in our consolidated balance sheet under other current assets and other noncurrent assets, respectively.
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 - 22 years
Leasehold improvements
5 - 20 years
Upon sale or retirement of property and equipment, including certain major components of our completion services 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 and businesses relates to replacement of major components like fluid and power ends. The Company recorded a loss on disposal of assets and businesses of $7.5 million, $73.0 million, and $102.1 million for the years ended December 31, 2024, 2023, and 2022, respectively.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
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. During the year ended December 31, 2024, we recorded property and equipment impairment expense of approximately $188.6 million in connection with our conventional Tier II diesel-only hydraulic fracturing pumping units and associated conventional assets, (the “Tier II Units”). No property and equipment impairment expense were recorded during the year ended December 31, 2023. During the year ended December 31, 2022, we recorded property and equipment impairment expense of approximately $57.5 million in connection with our DuraStim® electric-powered hydraulic fracturing equipment.
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 in a business combination. 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 than the carrying value, we consider goodwill to be impaired, and the amount of impairment loss is calculated and recorded in the statement of operations.
On May 31, 2024, we acquired AquaProp for $35.8 million. We accounted for the AquaProp Acquisition as a business combination using the acquisition method of accounting. Goodwill of $0.9 million was recorded within our hydraulic fracturing operating segment as of the AquaProp Acquisition Date (as defined below), which represents the excess of the purchase price over the fair value of the assets and liabilities assumed.
On November 1, 2022, we acquired Silvertip for $148.1 million. We accounted for the Silvertip Acquisition as a business combination using the acquisition method of accounting. Goodwill of $23.6 million was recorded within our wireline operating segment as of the Silvertip Acquisition Date (as defined below), which represents the excess of the purchase price over the fair value of the assets and liabilities assumed.
We conducted our annual impairment test of goodwill in accordance with ASC 350, Intangibles-Goodwill and Other, as of December 31, 2024, and determined that the goodwill in our wireline operating segment and reporting unit was fully impaired due to the Company updating its outlook for this reporting unit as a result of decreased revenue and profitability experienced during the year ended December 31, 2024. Accordingly, we recorded goodwill impairment expense of $23.6 million in our wireline reporting unit for the year ended December 31, 2024. No impairment to the carrying value of goodwill for our hydraulic fracturing reporting unit was required.
The following table summarizes goodwill by operating segment as of December 31, 2024, and 2023 and changes for the years then ended:
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
(in thousands)
Hydraulic Fracturing Wireline Total
Balance as of January 1, 2023
Goodwill $ - $ 23,624 $ 23,624
Accumulated impairment losses - - -
- 23,624 23,624
Goodwill acquired during year - - -
Impairment losses - - -
Balance as of December 31, 2023
Goodwill - 23,624 23,624
Accumulated impairment losses - - -
- 23,624 23,624
Goodwill acquired during year 3,130 - 3,130
Measurement period adjustment (2,210) - (2,210)
Impairment losses - (23,624) (23,624)
Balance as of December 31, 2024
Goodwill 920 23,624 24,544
Accumulated impairment losses - (23,624) (23,624)
$ 920 $ - $ 920
Intangible Assets - Intangible assets consist of customer relationships, trademark/trade name, favorable contracts acquired in connection with the acquisition of Silvertip and AquaProp and internally developed software costs. In connection with the acquisition of Silvertip, we added intangible assets consisting of $46.5 million of customer relationships and $10.8 million of trademark/trade name. In connection with the acquisition of AquaProp, we added intangible assets consisting of $18.6 million of customer relationships, $1.3 million of trademark/trade name and $2.2 million of favorable contracts. Intangible assets are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized on a straight-line basis over the asset’s estimated useful life. No significant residual value is estimated for intangible assets.
Leases - In accordance with ASC Topic 842, the Company determines if a contract is a lease at inception and evaluates identified leases for operating and finance lease accounting. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The Company uses a discount rate based on its estimated incremental borrowing rate on a collateralized basis with similar terms and economic considerations as its lease payments at the lease commencement in determining the present value of lease payments. Lease terms may include options to renew the lease or purchase the underlying assets, however, the Company typically cannot determine its intent to renew the lease or purchase the assets with reasonable certainty at inception. The Company elected the short-term lease recognition practical expedient provided by ASC 842 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. We elected to analogize to the measurement guidance of ASC 360 to capitalize costs incurred to place a leased asset into its intended use and to present such capitalized costs as part of the related lease right-of-use asset cost as initial direct costs.
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
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
Deferred Loan Costs - The Company capitalized certain costs in connection with the amendment and restatement of its revolving credit facility, 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, 2024, 2023, and 2022, the amount of expense recorded was $0.4 million, $0.4 million, and $0.8 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 or modification date, as applicable, 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.
Share Repurchases - All shares of common stock repurchased through the Company's share repurchase program are retired upon repurchase. The Company accounts for the purchase price of repurchased common stock in excess of par value ($0.001 per share of common stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction of retained earnings.
Variable Interest Entities - The Company may enter into strategic investments or other arrangements that are considered variable interests and such entities are considered variable interest entities (“VIE”). If the Company is the primary beneficiary of a VIE, it is required to consolidate the entity. To determine if the Company is the primary beneficiary of a VIE, the Company evaluates, at the inception of the Company’s involvement with a VIE and on an ongoing basis, whether it has (i) the power to direct the activities that most significantly impact the VIE’s economic performance, and (ii) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The assessment of whether the Company is the primary beneficiary of its VIE investments requires significant assumptions and judgments. VIEs that are not consolidated are accounted for under the measurement alternative, equity method, amortized cost, or other appropriate methodology based on the nature of the interest held.
Change in Accounting Estimates - Current trends in hydraulic fracturing equipment operating conditions such as larger pads, changes to job design and increased pumping hours per day have resulted in shorter useful lives for certain critical components that are included in our property and equipment assets. These recent trends necessitated a review of useful lives of our critical components like fluid ends, power ends, hydraulic fracturing units and other components in the first quarter of 2023. We determined that the estimated useful life of fluid ends is now less than one year, resulting in our determination that costs associated with the replacement of these components will no longer be capitalized, but instead recorded in inventories and amortized to cost of services over their estimated useful life. We have also shortened the estimated useful lives of power ends to two years from five years and hydraulic fracturing units to ten years from fifteen years. This change in accounting estimates was made effective January 1, 2023, and accounted for prospectively. The net effect of this change for the year ended December 31, 2024, was a $15.6 million increase in net loss, or $0.15 per basic and diluted share, respectively. The net effect of this change for the year ended December 31, 2023, was a $19.1 million decrease in net income, or $0.17 per basic and diluted share, respectively.
The Company plans to phase out its Tier II Units earlier than the current weighted average remaining useful life of this asset group in response to decreasing customer demand for and related pricing pressures on this asset group. Accordingly we shortened the remaining useful lives of those Tier II Units that currently have useful lives beyond 2027 to no longer than the
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SIGNIFICANT ACCOUNTING POLICIES (Continued)
end of 2027 to align with management's use and expected economic life. This change was made effective October 1, 2024. The net effect of this change for the year ended December 31, 2024, was a $1.7 million increase in net loss, or $0.02 per basic and diluted share, respectively.
Recently Issued Accounting Standards
In October 2023, the FASB issued Accounting Standards Update ("ASU") No. 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative. This ASU incorporates certain SEC disclosure requirements into the FASB Accounting Standards Codification (“Codification”). The amendments in the ASU represent changes to clarify or improve disclosure and presentation requirements of a variety of Codification topics, allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the requirements, and align the requirements in the Codification with the SEC’s regulations. ASU 2023-06 will become effective for each amendment on the effective date of the SEC's corresponding disclosure rule changes. We do not expect ASU 2023-06 to have a material impact on our consolidated financial statements.
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires public business entities to disclose on an annual and interim basis, 1) significant segment expenses that are regularly provided to the Chief Operating Decision Maker (the “CODM”) and included within each reported measure of segment profit or loss (collectively referred to as the “significant expense principle”) and 2) an amount for other segment items representing the difference between segment revenue less the segment expenses disclosed under the significant expense principle and each reported measure of segment profit or loss. This ASU also requires public entities to provide all annual disclosures about a reportable segment’s profit or loss and assets currently required by Topic 280 in interim periods, clarifies that if the CODM uses more than one measure of a segment’s profit or loss in assessing segment performance and deciding how to allocate resources, a public entity may report one or more of those additional measures of segment profit or loss but at least one of the reported segment profit or loss measures (or the single reported measure, if only one is disclosed) should be the measure that is most consistent with the measurement principles under GAAP. This ASU also requires disclosure of the title and position of the CODM and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources, and requires a public entity that has a single reportable segment to provide all the disclosures required by the amendments in this ASU and all existing segment disclosures in Topic 280. This ASU is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. We adopted this ASU 2023-07 for the fiscal year ended December 31, 2024, as required under this standard. See Note 11. Reportable Segment Information.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires disaggregation of certain components included in the Company’s effective tax rate and income taxes paid disclosures. The guidance is effective for annual periods beginning after December 15, 2024. We are currently assessing the impact of ASU 2023-09 on our consolidated financial statements but do not expect it will have a material impact.
In November 2024, the FASB issued ASU No. 2024-03, Income Statement: Reporting Comprehensive Income: Expense Disaggregation Disclosures (Subtopic 220-40), which requires public business entities to disclose, in the notes to financial statements, additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. In January 2025, the FASB issued ASU No. 2025-01, Clarifying the Effective Date, which revised the effective date of ASU No. 2024-03 for interim periods. The guidance is effective for annual periods beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. We are currently assessing the impact of ASU 2024-03 and ASU 2025-01 on our consolidated financial statements.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. SUPPLEMENTAL CASH FLOWS INFORMATION
(in thousands)
Year Ended December 31,
2024 2023 2022
Supplemental cash flows disclosures
Interest paid
$ 7,305 $ 4,564 $ 467
Income taxes paid
$ 1,792 $ 1,110 $ 129
Supplemental disclosure of noncash investing and financing activities
Capital expenditures included in accounts payable and accrued liabilities
$ 14,695 $ 21,604 $ 82,452
Insurance financing included in other current liabilities $ 5,479 $ - $ -
Business acquisition deferred cash consideration included in other current liabilities $ 3,664 $ - $ -
Business acquisition deferred cash consideration included in other long-term liabilities $ - $ 3,180 $ -
Business acquisition contingent consideration included in other long-term liabilities $ 10,900 $ - $ -
Common stock issued for business acquisition $ - $ - $ 106,736
Noncash purchases of property and equipment $ - $ - $ 2,668
Note receivable from sale of business $ 13,000 $ - $ -
Equity securities received in exchange for sale of assets $ - $ - $ 11,853
4. BUSINESS ACQUISITIONS
AquaProp Acquisition
On May 31, 2024, the Company completed the acquisition of all of the outstanding equity interests in AquaProp, which provides wet sand solutions for hydraulic fracturing sand requirements at oil well sites. As a result of the acquisition, the Company expanded its operations into the wet sand service business unit.
The following table summarizes the consideration transferred to AquaProp at the acquisition date:
(in thousands)
Fair value of purchase consideration:
Cash $ 21,216
Deferred cash consideration 3,664
Contingent consideration 10,900
Total consideration $ 35,780
Cash consideration includes $13.7 million paid to the seller, $7.2 million paid to settle the seller’s outstanding debt, and $0.3 million paid for the seller’s transaction expenses. The deferred cash consideration of $3.7 million will be used to cover the amount by which the estimated purchase price exceeds the final purchase price, if any. The unused amount is payable to the seller on May 31, 2025. This obligation is shown within other current liabilities in our consolidated balance sheets. As of December 31, 2024, the outstanding amount for this obligation was $3.7 million.
Included in the deferred cash consideration is a liability incurred to the seller of $1.8 million. In the purchase agreement as a post-closing transaction, AquaProp's seller agreed to purchase and then sell to the Company, and the Company agreed to purchase from the seller, two additional equipment spreads within 90 days of the closing at a purchase price equal to cost plus a 50% premium. The post-closing transaction was determined to be a transaction separate from the business combination, but the premium was determined to represent consideration transferred in the business combination as the above market terms of the arrangement would not have been agreed upon absent the business combination. Accordingly, the liability incurred to the seller was recognized as consideration in the business combination as cash was not paid at closing. The post-closing transaction for
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. BUSINESS ACQUISITIONS (Continued)
the Company’s purchase of the additional equipment occurred in July 2024 and the purchases were accounted for as additions to property and equipment in our consolidated balance sheet and capital expenditures in our consolidated statement of cash flows.
Also in the purchase agreement as an additional post-closing transaction, the seller agreed to purchase and then deliver to the Company up to five more additional equipment spreads at the request of the Company within a 30-month period following the delivery of the first additional spread at a purchase price equal to the lower of $4.8 million or cost. The additional post-closing transaction was determined to be a transaction separate from the business combination, but the Company recorded an intangible asset amounting to $0.3 million for the estimated fair value of the potential favorable pricing on such spreads as part of the consideration transferred in the business combination. This intangible asset is included within favorable contracts in the table below. The additional post-closing transaction for the Company’s purchase of the additional equipment will be accounted for as additions to property and equipment in our consolidated balance sheet and capital expenditures in our consolidated statement of cash flows.
The acquisition of AquaProp also included a contingent consideration arrangement that requires additional consideration to be paid by the Company to the seller based on the amount of wet sand delivered during a 30-month period following the delivery of the first additional spread, attributable to the five additional equipment spreads described above. Amounts are payable under the earnout arrangement if the Company reaches certain delivery thresholds (in tons) of wet sand using the specific equipment provided by the seller or by other parties. The range of the undiscounted amounts the Company could be obligated to pay under the contingent consideration agreement is between $0 and $12.5 million. The fair value of the contingent consideration for the business combination recognized at the acquisition date of $10.9 million was estimated by applying the probability-weighted expected return method for the different scenarios that may occur based on the amount of additional equipment delivered by the seller, at the request of the Company, and the amount of wet sand expected to be delivered by such equipment. The fair value measurement of the contingent consideration is based on significant inputs not observable in the market, and thus represent Level 3 measurements. The contingent consideration payable will be adjusted to estimated fair value at the end of each subsequent reporting period until the contingencies are resolved and consideration payments are made. The estimated fair value of the contingent consideration payable was $8.3 million at December 31, 2024, resulting in a $2.6 million decrease from May 31, 2024. The decrease in the estimated fair value of the contingent consideration payable was primarily driven by updated projections regarding the probability of different scenarios and the amount and timing of additional equipment to be delivered by the seller under those scenarios. The decrease in the estimated contingent consideration payable is included in general and administrative expenses in our consolidated statement of operations for the year ended December 31, 2024.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. BUSINESS ACQUISITIONS (Continued)
The following table summarizes the recognized amounts of identified assets, and liabilities assumed at the acquisition date:
(in thousands)
Recognized amounts of assets acquired and liabilities assumed:
Cash $ 178
Accounts receivable 10,551
Property and equipment 13,468
Intangible assets:
Trade name 1,300
Customer relationships 18,600
Favorable contracts 2,210
Accounts payable (1,423)
Factored receivables (10,024)
Total net assets acquired 34,860
Goodwill 920
Total consideration $ 35,780
The fair value of the assets acquired includes accounts receivable of $10.6 million. The gross amount due under contracts is $10.6 million, of which none is expected to be uncollectible. The Company did not acquire any other class of receivable as a result of the acquisition of AquaProp.
The assets acquired include three intangible assets, the trademark/trade name for AquaProp, customer relationships and favorable contracts. The trademark was assigned a fair value of $1.3 million with zero residual value and will be amortized on a straight-line basis over fifteen years. The customer relationships were assigned a fair value of $18.6 million with zero residual value and will be amortized on a straight-line basis over six years. The favorable contracts were assigned a fair value of $2.2 million with zero residual value out of which $0.3 million will be amortized over thirty months and $1.9 million will be amortized over five years. The fair value of the trademark was estimated using the relief-from-royalty method, which calculates the hypothetical royalty fees that would be saved by owning an intangible asset rather than licensing it from another owner. This method forecasts revenue over the estimated useful life of the asset and then applies the following: a royalty rate based on comparable royalty and/or licensing transactions, income tax rate and discount rate, to calculate the discounted cash flows to arrive at the value of the trademark. Key assumptions include revenue forecasted at historical trends with a 0% long-term growth rate, 1.0% royalty rate, 21.6% income tax rate and a 40.5% discount rate. The fair value of the customer relationships was estimated using the multi-period excess earnings method. This method is a specific application of the discounted cash flow method, in which revenue derived from the intangible asset is estimated using total business revenue as a proxy and subsequently adjusted for attrition. Then deductions are made for business expenses and required returns attributable to other assets in the business. The excess earnings after these deductions are discounted to present value at an appropriate rate of return to arrive at the intangible asset value. Key assumptions include revenue forecasted at historical trends with a 0% long-term growth rate, 20.0% attrition rate, 21.6% income tax rate and a 40.5% discount rate. The fair value of the favorable contracts was estimated using a discounted cash flow analysis. Key assumptions include forecasted revenue based on a probability-weighting of the number of spreads that will be active with a 0% long-term growth rate, 21.6% income tax rate and a 35.0% discount rate.
The goodwill is attributable to the acquired workforce and significant synergies. Goodwill is assigned 100% to the hydraulic fracturing operating segment of the Company. The goodwill recognized is deductible for income tax purposes.
During the period from May 31, 2024, to December 31, 2024, the Company made measurement period adjustments to recognize favorable contracts intangible assets of $2.2 million and decrease goodwill by $2.2 million and to increase accounts payable acquired as part of the acquisition of AquaProp by $0.5 million to reflect facts and circumstances in existence as of the acquisition date. The adjustment to accounts payable decreased the deferred cash consideration payable to the seller.
The acquired business generated revenues of $44.1 million and a net loss of $2.3 million for the period from May 31, 2024, to December 31, 2024.
The following combined supplemental unaudited pro forma information presents consolidated information of the Company as if the AquaProp Acquisition had occurred on January 1, 2023. The supplemental unaudited pro forma information presented
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. BUSINESS ACQUISITIONS (Continued)
below is for illustrative purposes only and does not reflect future events that occurred after December 31, 2024, or any operating efficiencies or inefficiencies that may result from the AquaProp Acquisition. The information is not necessarily indicative of results that would have been achieved had the Company controlled AquaProp during the periods presented. The information presented below does not include the year ended December 31, 2022, as AquaProp was formed in 2023.
(unaudited, in thousands)
Year Ended December 31,
2024 2023
Revenue $ 1,486,776 $ 1,653,010
Net (loss) income (126,736) 91,508
The Company had material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and net (loss) income. These adjustments included nonrecurring acquisition costs incurred in 2024 but have been adjusted to be reflected in 2023.
These pro forma amounts have been calculated after applying the Company’s accounting policies and adjusting the results of AquaProp to reflect the additional depreciation that would have been charged assuming the fair value adjustments to property and equipment had been applied from January 1, 2023, with the consequential tax effects.
For the year ended December 31, 2024, the Company incurred acquisition-related costs of $1.5 million. These expenses are included in general and administrative expenses on the Company’s consolidated statement of operations for the year ended December 31, 2024, and are reflected in pro forma net income for the year ended December 31, 2023, in the table above.
The Company’s consolidated statement of operations for the year ended December 31, 2024, includes 215 days of AquaProp operations as the AquaProp Acquisition closed on May 31, 2024.
Par Five Acquisition
On December 1, 2023, the Company completed the acquisition of certain assets and certain liabilities of Par Five which provides cementing and remediation services across the Permian Basin in Texas and New Mexico. As a result of the acquisition, the Company expanded its operations in the cementing service business unit.
The following table summarizes the consideration transferred to Par Five and the recognized amounts of identified assets acquired and liabilities assumed at the acquisition date:
(in thousands)
Total purchase consideration:
Cash $ 22,215
Deferred cash payment 3,109
Total consideration $ 25,324
(in thousands)
Recognized amounts of assets acquired and liabilities assumed:
Accounts receivable $ 8,641
Inventory 321
Property, plant and equipment 17,175
Accrued liabilities (813)
Total net assets acquired $ 25,324
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. BUSINESS ACQUISITIONS (Continued)
The deferred cash consideration of $3.1 million will be used to cover (i) the amount by which the estimated purchase price exceeds the final purchase price, if any and (ii) indemnity obligations of the seller. The unused amount is payable to Par Five or its beneficiary on June 1, 2025, and accrues interest at 4.0% per annum. This obligation is shown within other current liabilities in our consolidated balance sheet as of December 31, 2024. As of December 31, 2024, the outstanding amount for this obligation was $3.1 million.
The fair value of the assets acquired includes account receivables of $8.6 million. The gross amount due under contracts is $8.6 million, of which none is expected to be uncollectible. The Company did not acquire any other class of receivable as a result of the acquisition of Par Five. The Company previously recognized a preliminary estimate of $8.7 million for accounts receivable acquired as part of the Par Five Acquisition. During the year ended December 31, 2024, the Company made measurement period adjustments to net decrease accounts receivable by $0.1 million. These measurement period adjustments reflect facts and circumstances in existence as of the acquisition date. The cumulative impact of these adjustments was a decrease in deferred cash consideration payable.
The acquired business contributed revenues of $4.9 million and net income of $1.2 million to the Company for the period from December 1, 2023, to December 31, 2023.
The following combined supplemental unaudited pro forma information presents consolidated information of the Company as if the business combination had occurred on January 1, 2022. The supplemental pro forma information presented below is for illustrative purposes only and does not reflect future events that occurred after December 31, 2023, or any operating efficiencies or inefficiencies that may result from the Par Five Acquisition. The information is not necessarily indicative of results that would have been achieved had the Company controlled Par Five during the periods presented.
(unaudited, in thousands)
Year Ended December 31,
2023 2022
Revenue $ 1,672,350 $ 1,315,970
Net income 99,536 4,823
The Company had material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and net income. These adjustments included nonrecurring acquisition costs incurred in 2023 but have been adjusted to be reflected in 2022.
These pro forma amounts have been calculated after applying the Company’s accounting policies and adjusting the results of Par Five to reflect the additional depreciation that would have been charged assuming the fair value adjustments to property, plant, and equipment had been applied from January 1, 2022, with the consequential tax effects.
For the year ended December 31, 2023, the Company incurred $1.3 million of acquisition costs. These expenses are included in general and administrative expenses on the Company’s consolidated statement of operations for the year ended December 31, 2023, and are reflected in pro forma net income for the year ended December 31, 2022, in the table above.
The Company’s consolidated statement of operations for the year ended December 31, 2023, includes 31 days of Par Five operations as the Par Five Acquisition closed on December 1, 2023.
Silvertip Acquisition
On November 1, 2022 (the "Silvertip Acquisition Date"), the Company entered into a purchase and sale agreement with New Silvertip Holdco, LLC, pursuant to which the Company acquired 100% of the outstanding limited liability company interests of Silvertip, a wireline services company in the Permian Basin, in exchange for total consideration of $148.1 million (the "Silvertip Purchase Price") consisting of 10.1 million shares of the Company’s common stock valued at $106.7 million, $30.0 million of cash, the payoff of $7.2 million of assumed debt, and the payment of $4.1 million of certain seller closing and transaction costs.
The Company accounted for the Silvertip Acquisition using the acquisition method of accounting. The Silvertip Purchase Price was allocated to the major categories of assets acquired and liabilities assumed based upon their estimated fair value at the Silvertip Acquisition Date. The estimated fair values of certain assets and liabilities, including accounts receivable, require
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. BUSINESS ACQUISITIONS (Continued)
significant judgments and estimates. The measurements of assets acquired and liabilities assumed, are based on inputs that are not observable in the market and thus represent Level 3 inputs.
The following table summarizes the fair value of the consideration transferred in the Silvertip Acquisition and the Silvertip Purchase Price to the fair value of the assets acquired and liabilities assumed (which are included within the accompanying consolidated balance sheet as of December 31, 2022) as of the Silvertip Acquisition Date:
(in thousands)
Total purchase consideration:
Cash consideration $ 30,000
Equity consideration 106,736
Debt payments and closing costs 11,320
Total consideration $ 148,056
Cash and cash equivalents $ 2,681
Accounts receivable and unbilled revenue 21,079
Inventories 1,209
Prepaid expenses 2,476
Other current assets 1,059
Property and equipment (1)
52,478
Intangible assets:
Trademark/trade name (2)
10,800
Customer relationships (2)
46,500
Goodwill 23,624
Operating lease right-of-use asset 2,783
Total assets acquired 164,689
Accounts payable 7,659
Accrued and other current liabilities 6,178
Operating lease liability 2,796
Total liabilities assumed 16,633
Total purchase consideration $ 148,056
(1)Remaining useful lives ranging from less than one to 22 years.
(2)Definite lived intangibles with amortization period of 10 years.
The goodwill arising from the Silvertip Acquisition is attributable to the expected operational synergies resulting from our integrated service offerings. The goodwill arising from the Silvertip Acquisition has been allocated to our wireline operations, and are included in our wireline operating segment.
The Company’s transaction costs were recognized separately from the acquisition of assets and assumptions of liabilities in the Silvertip Acquisition, and were expensed as incurred. These costs are included within general and administrative expenses in our consolidated statements of operations.
The following combined pro forma information assumes the Silvertip Acquisition occurred on January 1, 2021. The pro forma information presented below is for illustrative purposes only and does not reflect future events that occurred after December 31, 2022, or any operating efficiencies or inefficiencies that may result from the Silvertip Acquisition. The information is not necessarily indicative of results that would have been achieved had the Company controlled Silvertip during the periods presented.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. BUSINESS ACQUISITIONS (Continued)
(unaudited, in thousands)
Year Ended December 31, 2022
Revenue $ 1,428,282
Net income 26,716
The Company’s consolidated statement of operations for the year ended December 31, 2022, includes 61 days of Silvertip operations as the Silvertip Acquisition closed on November 1, 2022.
5. FAIR VALUE MEASUREMENTS
Fair value 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.
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.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. FAIR VALUE MEASUREMENTS (Continued)
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The fair values of cash and cash equivalents, accounts receivable, accounts payable, accrued and other current liabilities, and long-term debt are estimated to be approximately equivalent to carrying amounts as of December 31, 2024, and 2023 and have been excluded from the table below.
Assets measured at fair value on a recurring basis as of December 31, 2024, are set forth below:
(in thousands)
Estimated fair value measurements
Balance
Quoted prices in
active market
(Level 1)
Significant other
observable inputs
(Level 2)
Significant other
unobservable inputs
(Level 3)
Total gains
(losses)
December 31, 2024:
Short-term investment $ 7,849 $ 7,849 $ - $ - $ 105
Business acquisition contingent consideration payable $ 8,300 $ - $ - $ 8,300 $ 2,600
December 31, 2023:
Short-term investment $ 7,745 $ 7,745 $ - $ - $ (2,538)
Short-term investment- On September 1, 2022, the Company received 2.6 million common shares of STEP Energy Services Ltd. (“STEP”) with an estimated fair value of $11.8 million as part of the consideration for the sale of our coiled tubing assets to STEP. The shares were treated as an investment in equity securities measured at fair value using Level 1 inputs based on observable prices on the Toronto Stock Exchange and are shown under current assets in our consolidated balance sheets. As of December 31, 2024, the fair value of the short-term investment was estimated at $7.8 million. The fluctuation in stock price resulted in an unrealized gain of $0.1 million for the year ended December 31, 2024, an unrealized loss of $2.5 million for the year ended December 31, 2023, and an unrealized loss of $1.6 million for the year ended December 31, 2022. Included in the unrealized gain for the year ended December 31, 2024, was a loss of $0.7 million resulting from noncash foreign currency translation. Included in the unrealized loss for the year ended December 31, 2023, was a gain of $0.1 million resulting from noncash foreign currency translation. Included in the unrealized loss for the year ended December 31, 2022, was a loss of $0.3 million resulting from noncash foreign currency translation. The unrealized gains and losses resulting from stock price fluctuation and noncash foreign currency translation are included in other income (expense) in our consolidated statements of operations. The Company is restricted from selling, transferring or assigning more than 0.9 million shares in any one calendar month.
Business acquisition contingent consideration payable- On May 31, 2024, the Company completed the acquisition of all of the outstanding equity interests in AquaProp in exchange for $13.7 million of cash, $3.7 million of deferred cash consideration payable to AquaProp's seller by May 31, 2025, the payoff of $7.2 million of assumed debt, the payment of $0.3 million of certain transaction costs and estimated contingent consideration of $10.9 million. The contingent consideration payable was measured at fair value using Level 3 inputs based on the probability-weighted expected return method and is shown under other long-term liabilities in our condensed consolidated balance sheets. The fair value of the contingent consideration payable is remeasured at the end of each reporting period. As of December 31, 2024, the estimated fair value of the contingent consideration payable was $8.3 million resulting in a $2.6 million decrease from May 31, 2024. The decrease in the estimated fair value of the contingent consideration payable was primarily driven by updated projections regarding the probability of different scenarios and the amount and timing of additional equipment to be delivered by the seller under those scenarios. Increases or decreases in any valuation inputs in isolation may result in a significantly lower or higher fair value measurement in the future.
The following table presents a reconciliation of the beginning and ending balances of the fair value measurements using significant unobservable inputs (Level 3):
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. FAIR VALUE MEASUREMENTS (Continued)
(in thousands)
Year Ended December 31, 2024
Business acquisition contingent consideration payable - opening balance $ -
Addition 10,900
Decrease in estimated fair value (1)
(2,600)
Business acquisition contingent consideration payable - closing balance $ 8,300
(1) The decrease in the estimated fair value of the business acquisition contingent consideration payable is included in other income (expense) in our consolidated statement of operations for the year ended December 31, 2024.
Assets Measured at Fair Value on a Nonrecurring Basis
Assets measured at fair value on a nonrecurring basis are set forth below:
(in thousands)
Estimated fair value measurements
Balance
Quoted prices in
active market
(Level 1)
Significant other
observable inputs
(Level 2)
Significant other
unobservable inputs
(Level 3)
Total gains
(losses)
December 31, 2024:
Implied fair value of wireline reporting unit goodwill (1)
$ - $ - $ - $ - $ (23,624)
November 1, 2024:
Note receivable on sale of Vernal, Utah cementing business $ 13,000 $ - $ 13,000 $ - $ -
September 30, 2024:
Property and equipment, net $ 63,791 $ - $ - $ 63,791 $ (188,601)
(1) The implied fair value of our wireline reporting unit was determined using Level 3 inputs and was $0 at December 31, 2024 (the measurement date) after full impairment.
Certain assets and liabilities are measured at fair value on a nonrecurring basis. These items are not measured at fair value on an ongoing basis but may be subject to fair value adjustments in certain circumstances. These assets and liabilities include those acquired through the business combinations, which are required to be measured at fair value on the acquisition date according to ASC Topic 805, Business Combinations (see Note 4. Business Acquisitions).
The Company performed a fair value assessment of the $13.0 million promissory note obtained as consideration for the sale of its cementing business located in Vernal, Utah, to Big 4 on November 1, 2024 (the date of the transaction), and concluded that the fair value of the note receivable approximated its carrying value and no discount or premium adjustment was needed. The Company utilized market interest rates for business loans which represented inputs other than quoted prices within Level 1 that are observable for the asset, either directly or indirectly (Level 2) to determine the implied fair value of the note receivable.
Whenever events or circumstances indicate that the carrying value of long-lived assets may not be recoverable, the Company reviews the carrying values of long-lived assets, such as property and equipment and other assets to determine if they are recoverable. If any long-lived assets are determined to be unrecoverable, an impairment expense is recorded in the period. As part of the quarterly evaluation for the three months ended September 30, 2024, after evaluating the current market conditions and new information available, such as decreasing customer demand for and related pricing pressures on its Tier II Units, among other factors, the Company determined that the marketability of its Tier II Units had declined. As a result, the Company plans to strategically phase out its Tier II Units before the end of the original weighted average remaining useful life of this asset group. The Company performed an impairment analysis on its Tier II Units as of September 30, 2024, by comparing estimated future cash flows on an undiscounted basis to the carrying value of these assets. The Company determined that its
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. FAIR VALUE MEASUREMENTS (Continued)
Tier II Units were impaired, as their carrying value was greater than their estimated future cash flows on an undiscounted basis. Accordingly, we recorded property and equipment impairment expense of approximately $188.6 million within our hydraulic fracturing operating segment during the year ended December 31, 2024, in connection with our Tier II Units. As of September 30, 2024 (the impairment measurement date), the estimated fair value of our Tier II Units was $63.8 million which was determined using the market and cost approaches, which represent Level 3 inputs in the fair value measurement hierarchy. Our fair value estimates required us to use significant unobservable inputs, including assumptions related to replacement cost, among others. The fair value of approximately 95% of our Tier II Units was estimated using the market approach and the remaining assets were valued using the cost approach. For assets valued using the market approach, we relied upon the direct match and comparable match methods of the market approach to value certain assets such as hydraulic fracturing pumps and their associated engines, transmissions, and power ends where significant market data was available and an active secondary market exists. Key assumptions include declining desirability for conventional diesel equipment due to emissions and fuel efficiency challenges based on research gathered from third party auctioneers. For assets valued using the cost approach, we estimated the current cost of reproducing a new replica of the asset being appraised using the same, or closely similar, materials for each asset or group of assets by using the indirect (trending) method of the cost approach. Allowances were made for physical deterioration as well as functional and economic obsolescence as appropriate. Key assumptions include forecasted use of Tier II Units. The carrying value of our Tier II Units as of September 30, 2024, prior to the impairment expense was approximately $252.4 million. No impairment of property and equipment was recorded during the year ended December 31, 2023. We recorded property and equipment impairment expense of approximately $57.5 million during the year ended December 31, 2022, in connection with our DuraStim® electric-powered hydraulic fracturing pumps that did not meet the manufacturer's specifications or our expectations.
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 3 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. We used both the guideline public company method and the guideline transaction method under the market approach. Significant assumptions include projected revenue growth, capital expenditures, 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. We conducted our annual impairment test of goodwill as of December 31, 2024, and determined that the goodwill in our wireline operating segment and reporting unit with a carrying value of $23.6 million was fully impaired due to the Company updating its outlook for this reporting unit as a result of decreased revenue and profitability experienced during the year ended December 31, 2024. Accordingly, we recorded goodwill impairment expense of $23.6 million in our wireline reporting unit for the year ended December 31, 2024. We applied weightings of 75%, 25%, and 0% to the fair values derived from the income approach, the guideline public company method and the guideline transaction method, respectively, to assess fair value. We used the Gordon Growth Model to determine the terminal value and applied a terminal growth rate of 3.0%, a 23.0% income tax rate and a 24.9% discount rate for the wireline reporting unit . No impairment to the carrying value of goodwill for our hydraulic fracturing reporting unit was required. There were no goodwill impairment losses during the years ended December 31, 2023, and 2022. See Note 2. Significant Accounting Policies for a summary of goodwill by operating segment.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. PROPERTY AND EQUIPMENT
Property and equipment consisted of the following:
(in thousands)
December 31,
2024 2023
Land
$ 14,076 $ 14,076
Buildings
40,342 37,888
Equipment and vehicles
1,040,242 1,551,261
Leasehold improvements
6,949 8,011
Subtotal
1,101,609 1,611,236
Less accumulated depreciation
(413,384) (644,120)
Property and equipment - net
$ 688,225 $ 967,116
Depreciation consisted of the following:
(in thousands)
Year Ended December 31,
2024 2023 2022
Depreciation related to cost of services $ 184,786 $ 169,771 $ 126,746
Depreciation related to general and administrative expenses 100 222 407
Total depreciation $ 184,886 $ 169,993 $ 127,153
The Company incurred amortization expense of $19.0 million and $5.2 million on its finance lease right-of-use asset, which is related to cost of services for the years ended December 31, 2024, and 2023, respectively. There was no amortization expense related to finance leases for the year ended December 31, 2022. The Company also incurred amortization expense on its intangible assets (see Note 7. Intangible Assets).
7. INTANGIBLE ASSETS
Intangible assets consist of trademark/trade name, customer relationships and favorable contracts. Trademark/trade names are amortized on a straight-line basis over useful lives of ten and fifteen years. Customer relationships are amortized on a straight-line basis over useful lives of six and ten years. Favorable contracts are amortized on a straight-line basis over useful lives of thirty months and five years. Internally developed software will be amortized on a straight-line basis over a useful life of twenty-nine months. Amortization expense, all of which was related to general and administrative expenses, was $7.9 million, $5.7 million and $1.0 million for the years ended December 31, 2024, 2023, and 2022, respectively. The Company’s intangible assets subject to amortization consisted of the following:
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. INTANGIBLE ASSETS (Continued)
(in thousands)
December 31,
2024 2023
Intangible assets acquired:
Trademark/trade name $ 12,100 $ 10,800
Customer relationships 65,100 46,500
Favorable contracts 2,210 -
Internally developed software 60 -
Total intangible assets 79,470 57,300
Accumulated amortization:
Trademark/trade name (2,390) (1,260)
Customer relationships (11,883) (5,425)
Favorable contracts (292) -
Total accumulated amortization (14,565) (6,685)
Intangible assets - net
$ 64,905 $ 50,615
Estimated remaining amortization expense for each of the subsequent fiscal years is expected to be as follows:
(in thousands)
Year Estimated future amortization expense
2025 $ 9,442
2026 9,432
2027 9,311
2028 9,301
2029 and beyond 27,419
Total $ 64,905
The average amortization period remaining is approximately 7.3 years.
8. LONG-TERM DEBT
Asset-Based Loan Credit Facility
Our revolving credit facility, as amended and restated in April 2022, prior to giving effect to the amendment to the revolving credit facility in June 2023, had a total borrowing capacity of $150.0 million. The revolving credit facility had a borrowing base of 85% to 90%, depending on the credit ratings of our accounts receivable counterparties, of monthly eligible accounts receivable less customary reserves. The revolving credit facility included a springing fixed charge coverage ratio to apply when excess availability was less than the greater of (i) 10% of the lesser of the facility size or the borrowing base or (ii) $10.0 million. Under the revolving credit facility, we were 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.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Effective June 2, 2023, the Company entered into an amendment to its amended and restated revolving credit facility. The amendment increased the borrowing capacity under the revolving credit facility to $225.0 million (subject to the Borrowing Base (as defined below) limit), and extended the maturity date to June 2, 2028.
Effective June 26, 2024, the Company entered into an amendment to its amended and restated revolving credit facility (the revolving credit facility, as amended and restated in April 2022, as amended in June 2023, as amended in June 2024, and as may be amended further, "ABL Credit Facility"). The amendment increased the amount of noncash consideration that may be considered cash pursuant to certain permitted dispositions. The ABL Credit Facility has a borrowing base of the sum of 85% to 90% of monthly eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the borrowing base), in each case, depending on the credit ratings of our accounts receivable counterparties, less customary reserves (the "Borrowing Base"), as redetermined monthly. The Borrowing Base as of December 31, 2024, was approximately $164.1 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) $15.0 million. Under the ABL Credit Facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens or indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.
Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either the Secured Overnight Financing Rate (“SOFR”) or the base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for SOFR loans and 0.75% to 1.25% for base rate loans. The weighted average annual interest rate for our ABL Credit Facility for the year ended December 31, 2024, was 7.12%.
The loan origination costs relating to the ABL Credit Facility are classified as an asset in our balance sheet. As of December 31, 2024, and 2023, we had outstanding borrowings under our ABL Credit Facility of $45.0 million and $45.0 million, respectively. After borrowings outstanding and letters of credit of approximately $8.6 million under the ABL Credit Facility, we had approximately $110.5 million available for borrowing under our ABL Credit Facility as of December 31, 2024.
9. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities consisted of the following:
(in thousands)
December 31,
2024 2023
Financed and accrued insurance $ 5,140 $ 1,222
Accrued payroll and related expenses
19,562 14,284
Deferred revenue (advance from customer) 11,823 19,190
Capital expenditure, taxes and other accruals
34,398 40,920
Total
$ 70,923 $ 75,616
10. EMPLOYEE BENEFIT PLAN
The Company has a 401(k) plan, modified effective January 1, 2019, and further modified effective April 1, 2022. The Company matches 100% of the employee contributions up to 6% of gross salary, up to the annual limit. The employees are fully vested in their contributions when made. Prior to the April 1, 2022, modification, the employees vested in the Company’s 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. Effective April 1, 2022, the Company allows for immediate vesting of the Company’s contributions. During the years ended December 31, 2024, 2023, and 2022, the recorded expense under the plan was $6.8 million, $5.9 million, and $4.6 million, respectively.
11. REPORTABLE SEGMENT INFORMATION
The Company currently has four operating segments for which discrete financial information is readily available: hydraulic fracturing (inclusive of acidizing and wet sand solutions), wireline, cementing and our newly formed power generation services
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. REPORTABLE SEGMENT INFORMATION (Continued)
which has not begun any revenue-generating activities yet. These operating segments represent how the CODM evaluates performance and allocates resources. Our CODM is a group comprised of our Chief Executive Officer, Chief Financial Officer, Chief Operating Officer and Chief Commercial Officer.
On November 1, 2024, the Company sold its cementing business located in Vernal, Utah, to a business owned by a former employee as part of a strategic repositioning. We recorded a gain on disposal of $8.2 million related to the sale of the business within loss on disposal of assets and business within our consolidated statement of operations for the year ended December 31, 2024. The sale of these assets did not qualify for presentation and disclosure as a discontinued operation, and accordingly, we have recorded the resulting gain from the sale as part of our loss on disposal of assets and business in our consolidated statement of operations. The former employee was part of the Company’s cementing operations until November 1, 2024 and is no longer affiliated with the Company.
On September 1, 2022, the Company shut down its coiled tubing operations and disposed of its coiled tubing assets to STEP as part of a strategic repositioning, and recorded a loss on disposal of $13.8 million. The divestiture of our coiled tubing assets did not qualify for presentation and disclosure as a discontinued operation, and accordingly, we have recorded the resulting loss from the disposal as part of our loss (gain) on disposal of assets in our consolidated statement of operations.
We have historically conducted our business through four operating segments: hydraulic fracturing, wireline, cementing and coiled tubing. Prior to the fourth quarter of fiscal year 2023, our operating segments met the aggregation criteria and were aggregated into the “Completion Services” reportable segment and our coiled tubing operations (which were divested in September 2022) were shown in the “All Other” category. Effective in the fourth quarter of fiscal year 2023, we revised our segment reporting as we determined that our operating segments no longer met the criteria to be aggregated. In the fourth quarter of fiscal year 2024, we formed a new subsidiary to provide power generation services. This new subsidiary has not begun any revenue-generating activities yet. Our hydraulic fracturing, wireline and cementing operating segments meet the criteria of a reportable segment. Our divested coiled tubing and our newly formed power generation services segments do not meet the reportable segment criteria and are included within the “All Other” category. Additionally, our corporate administrative activities do not involve business activities from which it may earn revenues and its results are not regularly reviewed by the Company’s CODM when making key operating and resource decisions. As a result, corporate administrative expenses have been included under “Reconciling Items.”
Our hydraulic fracturing operating segment revenue approximated 75.6%, 78.5% and 89.3% of our revenue for the years ended December 31, 2024, 2023, and 2022, respectively. Revenue from our wireline operating segment (resulting from the acquisition of Silvertip in 2022) approximated 14.1%, 14.1% and 2.4% of our revenue for the years ended December 31, 2024, 2023 and 2022, respectively. Our cementing operating segment revenue approximated 10.3%, 7.4% and 7.2% of our revenue for the years ended December 31, 2024, 2023 and 2022, respectively. Our newly formed power generation services operating segment has not begun any revenue-generating activities yet. Revenue from our coiled tubing operating segment which was divested in 2022 approximated 1.1% of our revenue for the year ended December 31, 2022. Our operating segments are subject to inherent uncertainties which may influence our prospective activities. Inter-segment revenues are not material and are not shown separately in the tables below.
The Company manages and assesses the performance of its reportable segments by their adjusted EBITDA (earnings before interest expense, income taxes, depreciation and amortization, stock-based compensation expense, other income or expense, gain or loss on disposal of assets and businesses and other unusual or nonrecurring expenses or income such as impairment charges, retention bonuses, severance, costs related to asset acquisitions, insurance recoveries, one-time professional fees and legal settlements). As part of the CODM’s review of segment-level performance, each member of the CODM group reviews the adjusted EBITDA of the Company’s reportable segments and provides expertise and analyses from their respective areas which drive the evaluation of the performance of the Company’s reportable segments and allocation of resources to those segments. Even though the CEO has the authority to override the other members for strategic or other reasons, key decisions are made jointly by the CODM group.
The following tables set forth certain financial information with respect to the Company’s reportable segments; intersegment revenues and cost of services are shown under “Reconciling Items” (in thousands):
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. REPORTABLE SEGMENT INFORMATION (Continued)
Hydraulic Fracturing Wireline Cementing All Other Reconciling Items Total
Year ended December 31, 2024
Service revenue (1)
$ 1,092,000 $ 203,182 $ 149,411 $ - $ (307) $ 1,444,286
Cost of service - labor $ 233,156 $ 53,609 $ 35,353 $ (6) $ - $ 322,112
Cost of service - expendables $ 149,809 $ 56,533 $ 67,986 $ - $ (307) $ 274,021
Cost of service - other direct costs $ 417,237 $ 37,983 $ 14,151 $ 10 $ - $ 469,381
General and administrative expenses excluding nonrecurring and non cash items for reportable segments $ 21,294 $ 11,200 $ 5,381 $ 366 $ - $ 38,241
Adjusted EBITDA for reportable segments $ 270,505 $ 43,857 $ 26,539 $ (370) $ - $ 340,531
Depreciation and amortization $ 182,188 $ 20,633 $ 8,812 $ - $ 100 $ 211,733
Property and equipment impairment expense (2)
$ 188,601 $ - $ - $ - $ - $ 188,601
Goodwill impairment expense (3)
$ - $ 23,624 $ - $ - $ - $ 23,624
Capital expenditures $ 116,257 $ 7,713 $ 9,376 $ - $ 42 $ 133,388
Goodwill $ 920 $ - $ - $ - $ - $ 920
Total assets $ 961,485 $ 156,349 $ 73,935 $ - $ 31,876 $ 1,223,645
Hydraulic Fracturing Wireline Cementing All Other Reconciling Items Total
Year ended December 31, 2023
Service revenue (1)
$ 1,280,523 $ 229,599 $ 120,277 $ - $ - $ 1,630,399
Cost of service - labor $ 239,037 $ 58,212 $ 27,871 $ - $ - $ 325,120
Cost of service - expendables $ 258,004 $ 61,883 $ 52,008 $ - $ - $ 371,895
Cost of service - other direct costs $ 389,115 $ 35,262 $ 10,409 $ - $ - $ 434,786
General and administrative expenses excluding nonrecurring and non cash items for reportable segments $ 27,559 $ 12,311 $ 5,324 $ - $ - $ 45,194
Adjusted EBITDA for reportable segments $ 366,809 $ 61,930 $ 24,665 $ - $ - $ 453,404
Depreciation and amortization $ 156,057 $ 18,762 $ 5,845 $ - $ 222 $ 180,886
Capital expenditures $ 294,377 $ 12,203 $ 3,440 $ - $ - $ 310,020
Goodwill $ - $ 23,624 $ - $ - $ - $ 23,624
Total assets $ 1,189,526 $ 198,957 $ 78,475 $ - $ 13,354 $ 1,480,312
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. REPORTABLE SEGMENT INFORMATION (Continued)
Hydraulic Fracturing Wireline Cementing All Other Reconciling Items Total
Year ended December 31, 2022
Service revenue (1)
$ 1,143,216 $ 31,188 $ 91,857 $ 13,440 $ - $ 1,279,701
Cost of service - labor $ 208,011 $ 8,046 $ 22,450 $ 6,007 $ - $ 244,514
Cost of service - expendables $ 246,558 $ 8,514 $ 41,427 $ 265 $ - $ 296,764
Cost of service - other direct costs $ 321,452 $ 4,582 $ 8,011 $ 7,497 $ - $ 341,542
General and administrative expenses excluding nonrecurring and non cash items for reportable segments $ 28,009 $ 2,120 $ 5,071 $ 1,135 $ - $ 36,335
Adjusted EBITDA for reportable segments $ 339,186 $ 7,926 $ 14,897 $ (1,463) $ - $ 360,546
Depreciation and amortization $ 117,753 $ 2,619 $ 5,089 $ 2,240 $ 407 $ 128,108
Property and equipment impairment expense (2)
$ 57,454 $ - $ - $ - $ - $ 57,454
Capital expenditures $ 347,757 $ 2,265 $ 7,769 $ 1,876 $ 5,649 $ 365,316
Goodwill $ - $ 23,624 $ - $ - $ - $ 23,624
Total assets $ 1,092,658 $ 173,489 $ 46,944 $ - $ 22,695 $ 1,335,786
____________________
(1)Revenue recognized over time under our Hydraulic Fracturing reportable segment was $1,077.2 million, $1,263.7 million and $1,133.2 million for the years ended December 31, 2024, 2023, and 2022, respectively. Revenue recognized at a point in time under our Hydraulic Fracturing reportable segment was $14.8 million, $16.8 million and $10.0 million for the years ended December 31, 2024, 2023, and 2022, respectively. All revenue under our Wireline reportable segment is recognized over time. All revenue under our All Other category is recognized at a point in time.
(2)Represents noncash property and equipment impairment expense on our Tier II Units for the year ended December 31, 2024 and noncash property and equipment impairment expense on our DuraStim® electric-powered hydraulic fracturing equipment for the year ended December 31, 2022. There was no impairment expense for the year ended December 31, 2023.
(3)Represents noncash impairment of goodwill in our wireline operating segment.
A reconciliation from reportable segment level financial information to the consolidated statements of operations is provided in the table below (in thousands):
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. REPORTABLE SEGMENT INFORMATION (Continued)
Year Ended December 31,
2024 2023 2022
Service Revenue
Hydraulic Fracturing $ 1,092,000 $ 1,280,523 $ 1,143,216
Wireline 203,182 229,599 31,188
Cementing 149,411 120,277 91,857
All Other - - 13,440
Total service revenue for reportable segments 1,444,593 1,630,399 1,279,701
Elimination of intersegment service revenue (307) - -
Total consolidated service revenue $ 1,444,286 $ 1,630,399 $ 1,279,701
Cost of Services
Hydraulic Fracturing - labor $ 233,156 $ 239,037 $ 208,011
Hydraulic Fracturing - expendables 149,809 258,004 246,558
Hydraulic Fracturing - other direct costs 417,237 389,115 321,452
Wireline - labor 53,609 58,212 8,046
Wireline - expendables 56,533 61,883 8,514
Wireline - other direct costs 37,983 35,262 4,582
Cementing - labor 35,353 27,871 22,450
Cementing - expendables 67,986 52,008 41,427
Cementing - other direct costs 14,151 10,409 8,011
All Other - labor (6) - 6,007
All Other - expendables - - 265
All Other - other direct costs 10 - 7,497
Total cost of services for reportable segments 1,065,821 1,131,801 882,820
Elimination of intersegment cost of services (307) - -
Total consolidated cost of services $ 1,065,514 $ 1,131,801 $ 882,820
General and Administrative Expenses
Hydraulic Fracturing $ 21,294 $ 27,559 $ 28,009
Wireline 11,200 12,311 2,120
Cementing 5,381 5,324 5,071
All Other 366 - 1,135
Total general and administrative expenses excluding nonrecurring and noncash items for reportable segments 38,241 45,194 36,335
Unallocated corporate administrative expenses 57,288 49,444 43,956
Stock-based compensation 17,288 14,450 21,881
Business acquisition contingent consideration adjustments (2,600) - -
Other general and administrative expense 1,782 2,969 8,460
Retention bonus and severance expense 2,324 2,297 1,128
Total consolidated general and administrative expenses $ 114,323 $ 114,354 $ 111,760
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. REPORTABLE SEGMENT INFORMATION (Continued)
Year Ended December 31,
2024 2023 2022
Adjusted EBITDA
Hydraulic Fracturing $ 270,505 $ 366,809 $ 339,186
Wireline 43,857 61,930 7,926
Cementing 26,539 24,665 14,897
All Other (370) - (1,463)
Total Adjusted EBITDA for reportable segments 340,531 453,404 360,546
Unallocated corporate administrative expenses (57,288) (49,444) (43,956)
Depreciation and amortization (211,733) (180,886) (128,108)
Property and equipment impairment expense (1)
(188,601) - (57,454)
Goodwill impairment expense (2)
(23,624) - -
Interest expense (7,815) (5,308) (1,605)
Income tax benefit (expense) 31,385 (29,868) (5,356)
Loss on disposal of assets and businesses, net (7,451) (73,015) (102,150)
Stock-based compensation (17,288) (14,450) (21,881)
Business acquisition contingent consideration adjustments 2,600 - -
Other income (expense), net (3)
5,531 (9,533) 11,582
Other general and administrative expense (4)
(1,782) (2,969) (8,460)
Retention bonus and severance expense (2,324) (2,297) (1,128)
Net (loss) income $ (137,859) $ 85,634 $ 2,030
Assets
Hydraulic Fracturing $ 961,485 $ 1,189,526 $ 1,092,658
Wireline 156,349 198,957 173,489
Cementing 73,935 78,475 46,944
All Other - - -
Total assets for reportable segments 1,191,769 1,466,958 1,313,091
Unallocated corporate assets 31,876 13,354 22,695
Total assets $ 1,223,645 $ 1,480,312 $ 1,335,786
(1)Represents the noncash property and equipment impairment expense of our Tier II Units for the year ended December 31, 2024, and the noncash property and equipment impairment expense of our DuraStim® electric-powered hydraulic fracturing equipment for the year ended December 31, 2022.
(2)Represents noncash impairment of goodwill in our wireline operating segment.
(3)Other income for the year ended December 31, 2024, is primarily comprised of tax refunds totaling (net of advisory fees) totaling $5.0 million and insurance reimbursements of $2.0 million, partially offset by a $2.0 million loss to a customer related to an accidental cementing job failure. Other expense for the year ended December 31, 2023, is primarily comprised of settlement expenses resulting from routine audits and one-time health insurance costs totaling approximately $7.4 million, and a $2.5 million unrealized loss on short-term investment. Other income for the year ended December 31, 2022 is primarily comprised of a $10.7 million net tax refund (net of advisory fees) received in March 2022 from the Texas Comptroller of Public Accounts in connection with limited sales, excise and use tax audit of the period from July 1, 2015, through December 31, 2018, $2.7 million of noncash income from fixed asset inventory received as part of a settlement of warranty claims with an equipment manufacturer, partially offset by and a $1.6 million unrealized loss on short-term investment.
(4)Other general and administrative expense for the year ended December 31, 2024, primarily relates to nonrecurring professional fees paid to external consultants in connection with our business acquisitions and legal settlements, net of reimbursement from insurance carriers. Other general and administrative expense for the year ended December 31, 2023, primarily relates to nonrecurring professional fees paid to external consultants in connection with our business acquisitions and legal settlements, net of reimbursement from insurance carriers. Other general and administrative expense for the year ended December 31, 2022, primarily relates to nonrecurring professional fees paid to external consultants in connection with our audit committee review, SEC investigation, shareholder litigation, legal settlement to a vendor and other legal matters, net of reimbursement from insurance carriers. During the years ended December 31, 2024, 2023, and 2022, we received reimbursement of approximately $0.2 million, $0.4 million, and $10.4 million, respectively, from our insurance carriers in connection with the SEC investigation and shareholder litigation.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. 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,
2024 2023 2022
Customer A 19.7 % 18.2 % 15.0 %
Customer B 14.9 % 6.2 % 0.0 %
Customer C 10.6 % 9.6 % 2.9 %
Customer D 6.9 % 4.8 % 0.8 %
Customer E 6.6 % 19.7 % 28.3 %
Customer F 2.6 % 0.5 % 1.4 %
Customer G 1.6 % 7.7 % 33.1 %
Customer H 0.0 % 2.3 % 4.7 %
The above customers are third-party customers. Revenue from these customers was derived our Hydraulic Fracturing, Wireline and Cementing segments and our All Other category.
12. 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 (“PSUs”) and restricted stock units (“RSUs”) 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,
2024 2023 2022
Numerator (both basic and diluted)
Net (loss) income relevant to common stockholders $ (137,859) $ 85,634 $ 2,030
Denominator
Denominator for basic net (loss) income per share 105,469 113,004 105,868
Dilutive effect of stock options - - 80
Dilutive effect of performance stock units - 42 506
Dilutive effect of restricted stock units - 370 485
Denominator for diluted net (loss) income per share 105,469 113,416 106,939
Basic net (loss) income per common share (1.31) 0.76 0.02
Diluted net (loss) income per common share (1.31) 0.76 0.02
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. NET INCOME (LOSS) PER SHARE (Continued)
As shown in the table below, the following stock options, RSUs and PSUs outstanding as of December 31, 2024, 2023, and 2022 have not been included in the calculation of diluted (loss) income per common share for the years ended December 31, 2024, 2023, and 2022 because they would be anti-dilutive to the calculation of diluted net (loss) income per common share:
(In thousands)
2024 2023 2022
Stock options 179 286 491
Restricted stock units 1 82 12
Performance stock units - 411 -
Total 180 779 503
13. SHARE REPURCHASE PROGRAM
On April 24, 2024, the Company's board of directors (the "Board") approved an increase and extension to the share repurchase program previously authorized on May 17, 2023. The program permits the repurchase of up to an additional $100 million of the Company's common stock for a total of $200 million and extends the expiration date by one year to May 31, 2025. The shares may be repurchased from time to time in open market transactions, block trades, accelerated share repurchases, privately negotiated transactions, derivative transactions or otherwise, certain of which may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act, in compliance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management's assessment of the intrinsic value of the Company's common stock, the market price of the Company's common stock, general market and economic conditions, available liquidity, compliance with the Company's debt and other agreements, applicable legal requirements, and other considerations. The Company is not obligated to purchase any shares under the share repurchase program, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund the repurchases using cash on hand and expected free cash flow to be generated through May 2025. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations applies to our share repurchase program.
All shares of common stock repurchased under the share repurchase program are canceled and retired upon repurchase. The Company accounts for the purchase price of repurchased shares of common stock in excess of par value ($0.001 per share of common stock) as a reduction of additional-paid-in capital, and will continue to do so until additional paid-in-capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction of retained earnings. During the year ended December 31, 2024, the Company paid an aggregate of $59.1 million, an average price per share of $8.21 including commissions, for share repurchases under the share repurchase program, thereby retiring 7.2 million shares. The Company has accrued $0.5 million in respect of the IRA 2022 repurchase excise tax as of December 31, 2024. As of December 31, 2024, $89.2 million remained authorized for future repurchases of common stock under the share repurchase program.
14. 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 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, and no further awards will be granted under the Stock Option Plan. As of December 31, 2024, there were no awards outstanding 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 was authorized to grant stock options, RSUs, 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
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. STOCK-BASED COMPENSATION (Continued)
In October 2020, our shareholders approved the ProPetro Holding Corp. 2020 Long Term Incentive Plan (the "2020 Incentive Plan") pursuant to which our Board may grant stock options, RSUs, PSUs, or other stock-based and cash awards to consultants, directors, executives and employees. The 2020 Incentive Plan authorized 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 on October 22, 2020, and as of such date no further awards will be granted under the 2017 Incentive Plan. In May 2023, our stockholders approved the Amended and Restated ProPetro Holding Corp. 2020 Long Term Incentive Plan (the "A&R 2020 Incentive Plan"), which had been previously approved by the Board. The A&R 2020 Incentive Plan became effective on May 11, 2023, and replaced the 2020 Incentive Plan. The A&R 2020 Incentive Plan authorizes up to 8,050,000 shares of common stock to be issued under awards granted pursuant to the plan in lieu of the 4,650,000 shares of common stock available for issuance under the 2020 Incentive Plan.
The 2017 Incentive Plan and the A&R 2020 Incentive Plan are herein collectively referred to as the "Incentive Plans."
Stock Options
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 were 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, 2024, 2023, and 2022.
As of December 31, 2024, there was no aggregate intrinsic value for our outstanding or exercisable stock options because the closing stock price as of December 31, 2024, was below the cost to exercise the options. No stock options were exercised during the year ended December 31, 2024. The weighted average remaining contractual term for the outstanding and exercisable stock options as of December 31, 2024, was 2.0 years and 2.0 years, respectively.
A summary of the stock option activity during the year ended December 31, 2024, is presented below (in thousands, except for exercise price):
Number
of Shares
Weighted
Average
Exercise
Price
Outstanding at January 1, 2024 180 $ 14.00
Granted - $ -
Exercised - $ -
Forfeited - $ -
Expired
(1) $ 14.00
Outstanding at December 31, 2024 179 $ 14.00
Exercisable at December 31, 2024 179 $ 14.00
Restricted Stock Units
In 2024, we granted 1,806,956 RSUs to employees, officers and directors pursuant to the A&R 2020 Incentive Plan, which generally vest ratably over a three-year vesting period or a two-year period at one-third after first year anniversary and two-thirds after the second year anniversary, 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 one share of common stock. 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, 2024, 2023, and 2022, the Company recognized stock compensation expense for RSUs of approximately $11.9 million, $7.8 million and $11.1 million, respectively.
On March 31, 2022, the Company modified the RSUs previously granted to a former officer in 2019, 2020, and 2021 to accelerate the vesting of such RSUs in connection with his separation agreement. On December 31, 2022, the Company modified the RSUs previously granted to a former officer in 2020, 2021, and 2022 to accelerate the vesting of such RSUs in connection with his separation agreement. As a result of these modifications, we recorded a net incremental stock expense of $1.2 million during the year ended December 31, 2022.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. STOCK-BASED COMPENSATION (Continued)
As of December 31, 2024, the total unrecognized compensation expense for all RSUs was approximately $15.9 million, and is expected to be recognized over a weighted-average period of approximately 1.6 years.
The following table summarizes the RSUs activity during the year December 31, 2024 (in thousands, except for fair value):
Number of
Shares Weighted
Average
Grant Date
Fair Value ("FV")
Outstanding at January 1, 2024 2,264 $ 9.81
Granted 1,807 $ 7.44
Vested (937) $ 9.51
Forfeited (133) $ 8.35
Canceled - $ -
Outstanding at December 31, 2024 3,001 $ 8.54
Performance Stock Units
In 2024, we granted 637,266 PSUs to certain key employees and officers as new awards under the A&R 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 of comparable companies (“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 simulation. 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.
In connection with a former officer’s separation agreement, on March 31, 2022, the Company modified the PSUs previously granted to such former officer in 2020 and 2021 to provide for deemed satisfaction of the service requirement applicable to such PSUs as of March 31, 2022, such that such PSUs shall remain outstanding and eligible to vest based on our TSR relative to the Peer Group over the applicable performance period. In connection with a former officer’s separation agreement, on December 31, 2022, the Company modified the PSUs previously granted to such former officer in 2021 and 2022 to provide for deemed satisfaction of the service requirement applicable to such PSUs as of December 31, 2022, such that such PSUs shall remain outstanding and eligible to vest based on our TSR relative to the Peer Group over the applicable performance period. As a result of these modifications, we recorded a net incremental stock expense of $2.6 million during the year ended December 31, 2022.
For the years ended December 31, 2024, 2023, and 2022, the Company recognized stock compensation expense for the PSUs of approximately $5.4 million, $6.6 million and $10.8 million, respectively.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. STOCK-BASED COMPENSATION (Continued)
The following table summarizes information about PSUs activity during the year ended December 31, 2024 (in thousands, except for fair value):
Period
Granted Target Shares Outstanding at January 1, 2024 Target
Shares
Granted Target Shares Vested Target
Shares
Forfeited Target Shares Outstanding at December 31, 2024
2021 620 - - (620) -
2022 306 - - (5) 301
2023 438 - - (7) 431
2024 - 637 - (4) 633
Total 1,364 637 - (636) 1,365
Weighted Average Fair Value Per Share $ 15.80 $ 8.22 $ - $ 14.73 $ 12.77
The total stock compensation expense for the years ended December 31, 2024, 2023 and 2022 for all stock awards was approximately $17.3 million, $14.5 million and $21.9 million, respectively, and the associated tax benefit related thereto was $3.6 million, $3.0 million and $4.6 million, respectively. The total unrecognized stock-based compensation expense as of December 31, 2024 was approximately $21.7 million, and is expected to be recognized over a weighted-average period of approximately 1.6 years.
15. INCOME TAXES
The components of the provision for income taxes are as follows:
(in thousands)
Year Ended December 31,
2024 2023 2022
Federal:
Current
$ 836 $ - $ -
Deferred
(33,756) 28,109 4,157
(32,920) 28,109 4,157
State:
Current
1,115 2,028 1,143
Deferred
420 (269) 56
1,535 1,759 1,199
Total income tax (benefit) expense
$ (31,385) $ 29,868 $ 5,356
Reconciliation between the amounts determined by applying the federal statutory rate of 21% for years ended December 31, 2024, 2023 and 2022 to income tax (benefit) expense is as follows:
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. INCOME TAXES (Continued)
(in thousands)
December 31,
2024 2023 2022
Taxes at federal statutory rate
$ (35,541) $ 24,256 $ 1,551
State taxes, net of federal benefit
1,194 2,092 709
Section 162(m) limitation 534 2,089 3,423
Stock-based compensation
2,168 1,718 (767)
Valuation allowance
- (780) (336)
Other
260 493 776
Total income tax (benefit) expense
$ (31,385) $ 29,868 $ 5,356
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,
2024 2023
Deferred Income Tax Assets
Accrued liabilities
$ 3,291 $ 1,410
Allowance for credit losses 0 50
Goodwill and other intangible assets
6,718 1,900
Stock-based compensation
2,083 1,979
Net operating losses
40,546 63,983
Lease liabilities
20,940 11,736
Other
877 895
Total deferred tax assets
74,455 81,953
Valuation allowance
(577) (577)
Total deferred tax assets - net
$ 73,878 $ 81,376
Deferred Income Tax Liabilities
Property and equipment
(110,856) (156,393)
Prepaid expenses
(1,691) (1,509)
Right-of-use assets (21,101) (16,579)
Total deferred tax liabilities
(133,648) (174,481)
Net deferred tax liabilities
$ (59,770) $ (93,105)
The Tax Cuts and Jobs Act included a reduction to the maximum deduction allowed for net operating losses generated after December 31, 2017, and the elimination of carryback of net operating losses. As of December 31, 2024, the Company had approximately $186.1 million of U.S. federal NOLs, all of which will have an unlimited carryforward. As of December 31, 2024, the Company’s state NOLs were approximately $42.8 million and will begin to expire in 2030. Utilization of NOLs may be limited under Section 382 of the Code due to future ownership changes. As of December 31, 2024, we determined that $0.6 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, 2021, 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, 2020, 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
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. INCOME TAXES (Continued)
largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority. As of December 31, 2024, 2023 and 2022, 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.
16. RELATED-PARTY TRANSACTIONS
Operations and Maintenance Yards
The Company rents three yards from an entity in which a director of the Company has an equity interest, and the total annual rent expense for each of the three yards was approximately $0.03 million, $0.1 million and $0.1 million, respectively. The Company previously rented two additional yards from this entity and incurred rent expense of $0.02 million and $0.1 million, respectively during the year ended December 31, 2023.
ExxonMobil and Pioneer
On December 31, 2018, we consummated the purchase of certain pressure pumping assets and real property from 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. In May 2024, Pioneer merged with and into a wholly owned subsidiary of Exxon Mobil Corporation (”ExxonMobil”) after which ExxonMobil became the owner of these shares. The Company currently provides pressure pumping, wireline and other services to ExxonMobil and previously provided such services to Pioneer.
On April 22, 2024, we entered into a sub-agreement for Hydraulic Fracturing Services with XTO Energy Inc. (“XTO), a wholly owned subsidiary of ExxonMobil, pursuant to which we will provide hydraulic fracturing, wireline and pumpdown services with two committed FORCE® electric-powered hydraulic fracturing fleets with the option to add a third FORCE® fleet (also with wireline and pumpdown services) for a period of three years or for contracted hours, whichever occurs last, with respect to each fleet, subject to certain termination and release rights.
Revenue from services provided to ExxonMobil (including Pioneer and XTO) subsequent to Pioneer's merger with ExxonMobil accounted for $187.7 million of our total revenue during the year ended December 31, 2024. Revenue from services provided to Pioneer (including equipment reservation fees) prior to its merger with ExxonMobil accounted for approximately $6.8 million of our total revenue during the year ended December 31, 2024. Revenue from services provided to Pioneer (including equipment reservation fees) prior to its merger with ExxonMobil accounted for approximately $125.1 million and $423.7 million of our total revenue during the years ended December 31, 2023 and 2022, respectively.
As of December 31, 2024, the total accounts receivable due from ExxonMobil (including Pioneer and XTO), including estimated unbilled receivable for services we provided, amounted to $70.8 million and the amount due to ExxonMobil (including Pioneer and XTO) was $0. As of December 31, 2023, the balance due from Pioneer for services we provided amounted to approximately $2.4 million and the amount due to Pioneer was $0.
Big 4 and Former Employee
On November 1, 2024, we sold our cementing business located in Vernal, Utah, to Big 4 which is solely owned by a former employee as part of a strategic repositioning. We received a promissory note for $13.0 million as consideration. The note receivable is secured by substantially all assets of Big 4 and the former employee’s ownership interests in and distributions from Big 4. The note receivable is to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025 to December 31, 2029. The note receivable is considered subordinated financial support to Big 4 and represents a variable interest to the Company in Big 4. See Note 19. Variable Interest Entity for the carrying value of the note receivable as of December 31, 2024. We recorded interest income of $0.2 million for the year ended December 31, 2024 which is included in our consolidated statement of operations under other income (expense). Cash inflows from collections on the note receivable will be included in our consolidated statement of cash flows under cash flows from investing activities. The former employee was part of our cementing operations until November 1, 2024, and is no longer affiliated with the Company.
17. LEASES
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. LEASES (Continued)
Operating Leases
Description of Leases
We have operating leases for five FORCE® electric-powered hydraulic fracturing equipment fleets (the “Electric Fleet Leases”), facilities and office space. The terms and conditions of these leases vary by the type of the underlying asset. We did not account for land separately from buildings under our leases of facilities because we concluded that the accounting effect was insignificant. Our operating leases do not include residual value guarantees, covenants or financial restrictions. Further, our operating leases do not contain variability in payments resulting from either an index change or rate change. We assumed two leases for facilities as part of our acquisition of Silvertip Completion Services Operating, LLC on November 1, 2022. Our operating leases have remaining lease terms of approximately 0.8 years to 3.9 years as of December 31, 2024. Our operating leases have renewal options ranging from none to three renewal options of up to one year each at the end of their current contractual lease periods. Further, our Electric Fleet Leases have options to purchase the underlying equipment at the end of their initial term of approximately three years or at the end of each renewal period. However, in management's judgment the exercise of neither the renewal options nor the purchase options are reasonably assured for any lease. In addition to fixed rent payments, the Electric Fleet Leases contain variable payments based on equipment usage. The right-of-use assets and liabilities related to the Electric Fleet Leases are included in our Hydraulic Fracturing reportable segment, related to leases for facilities are included in our Hydraulic Fracturing and Wireline reportable segments, and related to office space are included in our Wireline reportable segment and our corporate administrative function.
Year Ended December 31,
(in thousands) 2024 2023
Operating lease right of use cost $ 182,130 $ 85,775
Operating lease amortization of right-of-use assets 49,836 7,192
Net Book Value of Operating Leases $ 132,294 $ 78,583
Finance Leases
Description of Lease
We have a three-year equipment lease contract (the "Power Equipment Lease") for certain power generation equipment. In addition to the contractual lease period, the contract includes an optional renewal for one year, 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 Power Equipment Lease does not contain variability in payments resulting from either an index change or rate change. The right-of-use assets and liabilities under this contract are included in our Hydraulic Fracturing reportable segment.
We accounted for the Power Equipment Lease as a finance lease. This conclusion resulted from the existence of the right to control the use of the assets throughout the lease term, the present value of lease payments being equal to or in excess of substantially all of the fair value of the underlying assets and the lease term being the major part of the remaining economic life of the underlying assets.
Year Ended December 31,
(in thousands) 2024 2023
Finance lease right of use cost $ 54,842 $ 52,612
Finance lease amortization of right-of-use assets 24,129 5,163
Net Book Value of Finance Leases $ 30,713 $ 47,449
Lease Costs
The components of lease costs are as follows:
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. LEASES (Continued)
Year Ended December 31,
(in thousands) 2024 2023 2022
Operating lease cost $ 48,759 $6,636 $682
Finance lease cost:
Amortization of right-of-use assets 24,129 5,163 -
Interest on lease liabilities 2,892 1,014 -
Total finance lease cost 27,021 6,177 -
Variable lease cost 3,950 144 -
Short-term lease cost 833 830 825
Short-Term Leases
We elected the practical expedient option, consistent with ASC 842, to exclude leases with a term of twelve months or less ("short-term lease") from our balance sheet and continue to record short-term leases as a period expense.
Initial Direct Costs
We elected to analogize to the measurement guidance of ASC 360 to capitalize costs incurred to place a leased asset into its intended use and to present such capitalized costs as part of the related lease right-of-use asset cost as initial direct costs. The Company incurred initial direct costs of approximately $25.5 million, $25.0 million during the years ended December 31, 2024 and 2023, respectively, to place the leased equipment into its intended use, which are included in the right-of-use assets cost related to our Electric Fleet Leases. No initial direct costs were incurred during the year ended December 31, 2022.
Supplemental Cash Flow Information
Supplemental cash flow information related to leases are as follows:
Year Ended December 31,
(in thousands) 2024 2023 2022
Cash paid for amounts included in the measurements of lease liabilities:
Operating cash flows from operating leases $ 34,688 $ 4,573 $ 748
Operating cash flows from finance lease 2,892 1,014 -
Financing cash flows from finance lease 17,676 4,663 -
Noncash lease obligations arising from obtaining right-of-use assets related to:
Operating leases (1)
70,856 56,108 605
Finance lease (2)
2,230 52,612 -
(1)During the year ended December 31, 2024, we recorded noncash operating lease obligations arising from obtaining right-of-use assets related to the receipt of equipment under the Electric Fleet Leases. During the year ended December 31, 2023, we recorded noncash operating lease obligations arising from obtaining right-of-use assets related to the receipt of equipment under the Electric Fleet Leases, our execution of facilities and office leases and our extension of a facilities lease.
(2)During the year ended December 31, 2024, we recorded noncash finance lease obligations related to additional rent on the Power Equipment Lease. During the year ended December 31, 2023, we recorded noncash finance lease obligations arising from obtaining right-of-use assets related to the commencement of the Power Equipment Lease.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. LEASES (Continued)
Lease Terms and Discount Rates
Lease terms and discount rates are as follows:
December 31,
2024 2023
Weighted average remaining lease term:
Operating leases 2.4 years 3.1 years
Finance leases 1.6 years 2.6 years
Weighted average discount rate:
Operating leases 7.0 % 7.1 %
Finance leases 7.3 % 7.3 %
The discount rates used for our operating and finance leases are determined based on the weighted average annual interest rate on our ABL Credit Facility effective at the time of inception or modification of each lease.
Maturity Analysis of Lease Liabilities
The maturity analysis of liabilities and reconciliation to undiscounted and discounted remaining future lease payments for operating leases as of December 31, 2024 are as follows:
(in thousands) Operating Leases Finance Leases
2025 44,600 20,916
2026 43,835 13,462
2027 17,379 -
2028 820 -
2029 - -
2030 - -
Total undiscounted future lease payments $ 106,634 34,378
Amount representing interest (8,722) (1,874)
Present value of future lease payments (lease obligation) 97,912 32,504
18. 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. We entered into a contractual arrangement with an equipment manufacturer to purchase mobile natural gas-fueled power generation equipment for our PROPWR business line, with a total cost of $122.0 million, of which approximately $103.7 million, representing progress payments beyond the initial down payment on this equipment, will be financed. We currently expect to start receiving this equipment from the end of the second quarter of 2025 through early 2026. We entered into a contractual arrangement with another related equipment manufacturer to purchase additional natural gas-fueled power generation equipment for our PROPWR business line, with a total cost of $25.0 million. We currently expect to receive these generators in the first half of 2025. The power generation equipment from these contractual arrangements represent total capacity of 140 megawatts.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18. COMMITMENTS AND CONTINGENCIES (Continued)
We entered into the Electric Fleet Leases, which contain options to extend the leases or purchase the equipment at the end of each lease or at the end of each subsequent renewal period. As of December 31, 2024, all five of the Electric Fleet Leases commenced when the Company took possession of all equipment associated with the first four FORCE® electric-powered hydraulic fracturing fleets and some of the equipment associated with the fifth fleet under these leases. Lease payments pertaining to the remaining equipment under the fifth Electric Fleet Lease is expected to commence when the Company takes possession of the remaining associated equipment. We currently expect to receive the remaining equipment associated with the fifth fleet in the first half of 2025. The total estimated contractual commitment in connection with the Electric Fleet Leases excluding the cost associated with the option to purchase the equipment at the end of each lease is approximately $121.8 million. We also entered into the Power Equipment Lease. The total estimated contractual commitment in connection with the Power Equipment Lease is approximately $34.4 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 the Sand Suppliers expire at December 31, 2025. Our sand agreement with one of our Sand Suppliers that will expire on December 31, 2025, has a take-or-pay commitment of $1.5 million. During the years ended December 31, 2024, 2023, and 2022, no shortfall fee was recorded.
As of December 31, 2024 and 2023, the Company had issued letters of credit of $8.6 million and $6.0 million, respectively, under the ABL Credit Facility in connection with the Company's casualty insurance policy.
Contingent Liabilities
Legal Matters
We have been named in various claims, lawsuits or threatened actions in the ordinary course of our business. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of any claim, lawsuit or action cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of any litigation matter. Any claims against us, whether meritorious or not, could cause us to incur significant costs and expenses and require significant amounts of management and operational time and resources. With respect to each matter or exposure, we have made an assessment, in accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be estimated, we record a liability at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected to result from these matters. In the opinion of our management, no pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.
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.
The Company is self-insured up to $10 million per occurrence for certain losses arising from or attributable to fire and/or explosion at the wellsites that do not have qualified fire suppression measures. No accrual was recorded in our financial statements in connection with this self-insurance strategy because the occurrence of fire and/or explosion cannot be reasonably estimated.
PROPETRO HOLDING CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18. COMMITMENTS AND CONTINGENCIES (Continued)
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, 2024, the audit was substantially complete and the Company accrued for an estimated settlement expense of $6.0 million.
In May 2022, the Company received a notification from the Comptroller that it will commence a routine audit of the Company’s gross receipt taxes, which will routinely cover up to a four-year period. As of December 31, 2024, the audit was nearing completion and the Company accrued for an estimated settlement expense of $0.8 million.
19. VARIABLE INTEREST ENTITY
A VIE is an entity with any of the following characteristics: (i) the entity does not have enough equity to finance its activities without additional financial support, (ii) the equity holders, as a group, lack the characteristics of a controlling financial interest or (iii) the entity is structured with non-substantive voting rights. Consolidation of a VIE is required for the party deemed to be the primary beneficiary, if any. The primary beneficiary is the party who has both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.
On November 1, 2024, we sold our cementing business located in Vernal, Utah, to a Big 4, which is solely owned by a former employee as part of a strategic repositioning. We received a promissory note for $13.0 million as consideration. The note receivable is secured by substantially all assets of Big 4 and the former employee’s ownership interests in and distributions from the entity. The note receivable is to be paid to the Company in quarterly installments with interest of 10% per annum from March 31, 2025 to December 31, 2029. We evaluated our note receivable from Big 4 for VIEs in accordance with ASC 810, Consolidation. The Company holds a variable interest in Big 4 and Big 4 is a VIE due to its lack of sufficient equity to finance its operations without additional subordinated financial support from the Company. The note receivable from Big 4 is considered subordinated financial support and represents a variable interest to the Company in Big 4. Assets and liabilities related to the Company’s variable interest in Big 4 included in the Company’s consolidated balance sheets are limited to the unpaid balance of the note receivable and any accrued interest. The Company’s maximum exposure to loss as a result of its involvement with Big 4 is also limited to the unpaid balance of the note receivable and any accrued interest. The consolidation of Big 4 is not required as the Company is not the primary beneficiary of this VIE as we do not have the power to direct the activities that most significantly impact Big 4’s economic performance. We consider such activities to include performing customer contract obligations, maintaining and establishing customer relationships, and managing costs, among other operational activities. We do not have any control over such activities. Such power is held by Big 4’s sole owner. We account for the note receivable (our variable interest) at amortized cost. As of December 31, 2024, the carrying value of the note receivable including interest was $13.2 million. Of the carrying value at December 31, 2024 the amount collectible within one year was $2.1 million and the amount collectible beyond one year was $11.1 million, which are included in our consolidated balance sheet under other current assets and other non current assets, respectively.

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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 Form 10-K. 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, 2024. As noted in Management’s Report on Internal Control over Financial Reporting, management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of AquaProp, which was acquired on May 31, 2024. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. We are in the process of integrating AquaProp’s internal controls with our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed.
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 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, 2024, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management believes that ProPetro Holding Corp. maintained effective internal control over financial reporting as of December 31, 2024. Management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of AquaProp, which was acquired on May 31, 2024, and whose financial statements constitute 4.9% and 3.1% of total assets and revenue, respectively of the consolidated financial statement amounts as of and for the year ended December 31, 2024. The independent registered public accounting firm, RSM US LLP, Houston, Texas, United States, has audited the consolidated financial statements as of and for the year ended December 31, 2024, 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 Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2024, 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
Trading Plans
During the three months ended December 31, 2024, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
The information required by Item 10 is incorporated by reference to the Company’s Proxy Statement for its 2025 Annual Meeting of Stockholders, which is expected to be filed before the end of April 2025.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by Item 11 is incorporated by reference to the Company’s Proxy Statement for its 2025 Annual Meeting of Stockholders, which is expected to be filed before the end of April 2025.

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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
The information required by Item 12 is incorporated by reference to the Company’s Proxy Statement for its 2025 Annual Meeting of Stockholders, which is expected to be filed before the end of April 2025.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Party Transactions, and Director Independence.
The information required by Item 13 is incorporated by reference to the Company’s Proxy Statement for its 2025 Annual Meeting of Stockholders, which is expected to be filed before the end of April 2025.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The information required by Item 14 is incorporated by reference to the Company’s Proxy Statement for its 2025 Annual Meeting of Stockholders, which is expected to be filed before the end of April 2025.
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 1, 2022, between ProPetro Holding Corp. and New Silvertip Holdco, LLC (incorporated by reference herein to Exhibit 2.1 to ProPetro Holding Corp.’s Current Report on Form 8-K dated October 31, 2022).
3.1 Amended and Restated Certificate of Incorporation of ProPetro Holding Corp., dated as of June 19, 2019 (incorporated by reference herein to Exhibit 3.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated June 19, 2019).
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).
10.1# 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)).
10.2# 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).
10.3# 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)).
10.4# 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)).
10.5# 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).
10.6# 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).
10.7# 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).
10.8# 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).
10.9# 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).
10.10# 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).
10.11# 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).
10.12# 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).
10.13# 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).
10.14 Restatement Agreement, dated as of April 13, 2022, by and among ProPetro Holding Corp., and ProPetro Services, Inc., Barclays Bank PLC, as the Administrative Agent, the Collateral Agent, a Letter of Credit Issuer and the Swingline Lender, and each of the Lenders and Letter of Credit Issuers 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 April 13, 2022).
10.15# Amended and Restated ProPetro Holding Corp. 2020 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, dated May 11, 2023).
10.16 Amendment No. 1 to Amended and Restated Credit Agreement, dated as of June 2, 2023, by and among ProPetro Holding Corp., and ProPetro Services, Inc., the Incremental Lenders and each existing Lender party thereto as a Consenting Lender and Barclays Bank PLC, as Agent (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K, dated June 2, 2023).
10.17# Amended and Restated ProPetro Holding Corp. Non-Employee Director Compensation Policy (incorporated by reference herein to Exhibit 10.1 of ProPetro Holding Corp.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023).
10.18# Sub-agreement for Hydraulic Fracturing Services effective as of April 22, 2024, between XTO Energy Inc. (a wholly owned subsidiary of Exxon Mobil Corporation) and ProPetro Services, Inc. (incorporated by reference herein to Exhibit 10.1 of ProPetro Holding Corp’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2024).
10.19 Amendment No. 2 to Amended and Restated Credit Agreement, dated as of June 26, 2024, by and among ProPetro Holding Corp., and ProPetro Services Inc. the Incremental Lenders and each existing Lender party thereto as a Consenting Lender and Barclays Bank PLC, as Agent (incorporated by referenced herein to Exhibit 10.2 to ProPetro Holding Corp.’s Quarterly Financial Report on Form 10-Q for the quarter ended June 30, 2024).
16.1 Letter of Deloitte & Touche LLP dated March 1, 2023 (incorporated by reference herein to Exhibit 16.1 to ProPetro Holding Corp.’s Current Report on Form 8-K, dated March 1, 2023).
19.1(a) Insider Trading Policy
21.1(a) List of Subsidiaries of ProPetro Holding Corp.
23.1(a) Consent of RSM US LLP, an Independent Registered Public Accounting Firm.
23.2(a) Consent of Deloitte & Touche LLP, an 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.
97.1# ProPetro Holding Corp. Incentive-Based Compensation Recovery (Clawback) Policy (incorporated by reference herein to Exhibit 97.1 to ProPetro Holding Corp.’s Annual Report on Form 10-K for the year ended December 31, 2023).
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.