ProPetro Holding Corp

Previous wording

We are a leading integrated oilfield service company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline and other complementary oilfield completion services to leading upstream oil and gas companies engaged in the exploration and production (“E&P”) of North American oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region’s most active and well‑capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil‑producing areas in the United States, and we believe we are one of the leading providers of completion services in the region.

Current wording

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.

Previous wording

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

Current wording

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. Ourhydraulic 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 fleetand 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.

Previous wording

On December 1, 2023, we consummatedthe purchase of the assets and operations of Par Five Energy Services LLC (“Par Five”), which provides cementing services in the Delaware Basin, in exchange for$25.4 million of cash. Par Five’s business complements our existing cementing business and enables us to serve both the Midland and Delaware Basins of the Permian Basin.

Current wording

On December 1, 2023, we consummatedthe 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.

Previous wording

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 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. At December 31, 2023, we had 23 wireline units available to provide wireline perforation and ancillary services. The Silvertip Acquisition positions the Company as a more resilient and diversified completions-focused oilfield service provider headquartered in the Permian Basin.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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

Current wording

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.”

Previous wording

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 Acquisitionin exchange for 16.6 million shares of our common stock and$110.0 million in cash, and concurrently entered into a pressure pumping services agreement (the "Pioneer Services Agreement") with Pioneer.

Current wording

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.

Previous wording

Similarly, the geopolitical and macroeconomic consequences of the Russian invasion of Ukraine, including the associated sanctions, and the adverse impacts of the COVID-19 pandemic in recent years 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 nine years. However, in 2023, the WTI average crude oil price declined to approximately $78 per barrel. 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 ongoing conflict between Israel and Palestinian militants in the Israel-Gaza region, slower crude oil production growth due to the lack of reinvestment in the oil and gas industry in the last two years, recent OPEC+ production cuts of approximately 1.3 million barrels per day and concerns of a potential global recession resulting from high inflation and interest rates.

Current wording

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.

Previous wording

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 oilfield service industry has experienced increased demand for its completion services, and improved pricing. However, we have recently experienced a 13% decrease in the rig count in 2023 to 309 at the end of 2023 which resulted in a reduction in the demand for completion services and pressure on pricing of our services.

Current wording

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.

Previous wording

Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including 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, or further declines in crude oil prices 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."

Current wording

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.”

Previous wording

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

Current wording

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.

Previous wording

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

Current wording

•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;

Previous wording

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

Current wording

•despite market volatility, our average active hydraulic fracturing fleet count was approximately 14 fleets, a decrease from 15 active fleets in 2023;

Previous wording

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

Current wording

•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;

Previous wording

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

Current wording

•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 ourconventional 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”);

Previous wording

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

Current wording

•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

Previous wording

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

Current wording

•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.

Previous wording

Completion services includes our hydraulic fracturing, wireline and cementing operations. We primarily provide these services to E&P comp anies in the Permian Basin. During the year ended December 31, 2023, our hydraulic fracturing, wireline and cementing operations accounted for 78.5%, 14.1% and 7.4% of our total revenue, respectively. Our equipment has been designed to handle Permian Basin specific operating conditions and the region’s increasingly high‑intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. We plan to continually reinvest in our equipment to ensure optimal performance and reliability.

Current wording

Completion services includes our hydraulic fracturing, wireline and cementing operations. We primarily provide these services to E&P comp anies 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.

Previous wording

We generate revenue through our completion services, and more specifically, by providing hydraulic fracturing services to our customers. We own and 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.

Current wording

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.

Previous wording

In addition to hydraulic fracturing services, we generate revenue through other completion services that we provide to our customers, including cementing, wireline 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.

Current wording

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.

Previous wording

Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. The average WTI oil price per barrel was approximately $78, $94 and $68 for the years ended December 31, 2023, 2022 and 2021, respectively. In January 2024, the WTI oil price was approximately $74 per barrel. If the WTI oil price declines in the future or remains highly volatile, demand for our services may be negat ively 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.

Current wording

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 negat ively 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.

Previous wording

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

Current wording

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.

Previous wording

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

Current wording

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

Previous wording

Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental and other miscellaneous operating expenses. Fuel is consumed both in the operation and movement of our equipment. Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs. Capital expenditures to upgrade or extend the useful life of equipment are capitalized and are not included in other direct costs. Other direct costs were 38.4% and 38.7% of total costs of service for the years ended December 31, 2023 and 2022, respectively.

Current wording

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.

Previous wording

We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our earnings, before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock-based compensation, (iii) other expense/(income) and (iv) other unusual or nonrecurring (income)/expenses, such as impairment charges, retention bonuses, severance, costs related to asset acquisitions, insurance recoveries, one-time professional fees and legal settlements. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.

Current wording

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.

Previous wording

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 GAAP.

Current wording

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”).

Previous wording

(1)Includes settlement expenses resulting from routine audits.

Current wording

(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.

Previous wording

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

Current wording

(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.”

Previous wording

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

Current wording

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:

Previous wording

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

Current wording

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:

Previous wording

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

Current wording

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.

Previous wording

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

Current wording

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 ofour 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.

Previous wording

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

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

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

Current wording

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.

Previous wording

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

Current wording

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 wereno amounts of restricted cashas of December 31, 2024 and 2023.

Previous wording

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

Current wording

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.

Previous wording

On May 17, 2023, the Board authorized and the Company announced a share repurchase program that allows the Company to repurchase up to $100 million of the Company's common stock beginning immediately and continuing through and including May 31, 2024. The shares may be repurchased from time to time in open market transactions, block trades, accelerated share repurchases, privately negotiated transactions, derivative transactions or otherwise, certain of which may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act, as amended, in compliance with applicable state and federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management's assessment of the intrinsic value of the Company's common stock, the market price of the Company's common stock, general market and economic conditions, available liquidity, compliance with the Company's debt and other agreements, applicable legal requirements, and other considerations. The Company is not obligated to purchase any shares under the repurchase program, and the program may be suspended, modified, or discontinued at any time without prior notice. The Company expects to fund the repurchases using cash on hand and expected free cash flow to be generated through May 2024. During the year ended December 31, 2023, the Company repurchased and retired 5.8 million shares of common stock for an aggregate of $51.7 million, an average price per share of $8.93 including commissions, under the repurchase program. As of December 31, 2023, $48.3 million remained authorized for future repurchases of common stock under the repurchase program.

Current wording

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.