Liberty Energy Inc

Previous wording

The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas E&P companies in North America. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing and treating, CNG delivery, data analytics, related goods (including our sand mine operations), and technologies that will facilitate lower emission completions, thereby helping our customers reduce their emissions profile. We have grown from one active hydraulic fracturing fleet in December 2011 to over 40 active fleets as of December 31, 2023. We provide our services primarily in the Permian Basin, the Williston Basin, the Eagle Ford Shale, the Haynesville Shale, the Appalachian Basin (Marcellus Shale and Utica Shale), the Western Canadian Sedimentary Basin, the DJ Basin, and the Anadarko Basin. Our operations also extend to a few smaller shale basins, including the Uinta Basin, the Powder River Basin, and the San Juan Basin, as well as to two sand mines in the Permian Basin.

Current wording

The Company, together with its subsidiaries, is a leading integrated energy services and technology company focused on providing innovative hydraulic fracturing services and related technologies to onshore oil and natural gas E&P companies. We offer customers hydraulic fracturing services, together with complementary services including wireline services, proppant delivery solutions, field gas processing and treating, CNG delivery, data analytics, related goods (including our sand mine operations), and technologies to facilitate lower emission completions, thereby helping our customers reduce their emissions profile. We have grown from one active hydraulic fracturing fleet in December 2011 to approximately 40 active fleets as of December 31, 2024. We provide our services primarily in the Permian Basin, the Williston Basin, the Haynesville Shale, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Western Canadian Sedimentary Basin, the Powder River Basin, and the Appalachian Basin (Marcellus Shale and Utica Shale). Our operations also extend to a few smaller shale basins, including the Anadarko Basin, the Uinta Basin, the San Juan Basin, and the Beetaloo Basin in Northern Territory, Australia, as well as to two sand mines in the Permian Basin.

Previous wording

In early 2023, the Company launched Liberty Power Innovations LLC (“LPI”), an integrated alternative fuel and power solutions provider for remote applications. LPI provides CNG supply, field gas processing and treating, and well site fueling and logistics. LPI was formed with the initial focus on supporting Liberty’s transition towards our next generation digiFleets℠ and dual fuel fleets, as CNG fueling services are limited in the market, yet critical to maintaining highly efficient well site operations. Currently, LPI is primarily focused on supporting an industry transition to natural gas fueled technologies, serving as a key enabler of the next step of cost and emissions reductions in the oilfield.

Current wording

In early 2023, the Company launched Liberty Power Innovations LLC (“LPI”), an integrated alternative fuel and power solutions provider for remote applications. LPI provides CNG supply, field gas processing and treating, and well site fueling and logistics. LPI was formed with the initial focus on supporting the Company’s transition towards our next generation digiFleets℠ and dual fuel fleets, as CNG fueling services can be limited in the market, yet critical to maintaining highly efficient well site operations. Through 2024, LPI was primarily focused on supporting an industry transition to natural gas fueled technologies, serving as a key enabler of the next step of cost and emissions reductions in the oilfield. In January 2025, we announced LPI’s expansion into the distributed power business, where we expect to leverage our experience in providing electric power for our digiFrac pumps into other areas inside and outside of the oilfield.

Previous wording

We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending (“DGB”) fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) our digiFleets℠, comprising of digiFrac℠ and digiPrime℠ pumps, our innovative, purpose-built electric and hybrid frac pumps that have approximately 25% lower CO2e emission profile than the Tier IV DGB; (vi) our wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites; and (vii) the launch of LPI to support the transition to our digiFleets as well as the transition to lower costs and emissions in the oilfield.. In addition, our integrated supply chain includes proppant, chemicals, equipment, natural gas fueling services, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle in the regions we operate.

Current wording

We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business. We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations. We remain proactive in developing innovative solutions to industry challenges, including developing: (i) our databases of U.S. unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (iv) our dual fuel dynamic gas blending (“DGB”) fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs; (v) our digiFleets℠, comprising of digiFrac℠ and digiPrime℠ pumps and other complementary equipment, including power generation units (together “digiTechnologies℠”), our innovative, purpose-built electric and hybrid frac pumps that have approximately 25% lower CO 2e emission profile than the Tier IV DGB; (vi) our wet sand handling technology which eliminates the need to dry sand, enabling the deployment of mobile mines nearer to wellsites; and (vii) the launch of LPI to support the transition to our digiFleets as well as the transition to lower costs and emissions in the oilfield. In addition, our integrated supply chain includes proppant, chemicals, equipment, natural gas fueling services, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers. In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle in the regions we operate.

Previous wording

During the year 2023, the posted WTI price traded at an average of $77.58 per barrel (“Bbl”), as compared to the 2022 average of $94.90 per Bbl, and the 2021 average of $68.13 per Bbl. In addition, the average domestic onshore rig count for the United States and Canada was 781 rigs reported in the fourth quarter of 2023, down from the average in the fourth quarter of 2022 of 947, according to a report from Baker Hughes.

Current wording

During the year 2024, the posted WTI price traded at an average of $76.63 per barrel (“Bbl”), as compared to the 2023 average of $77.58 per Bbl, and the 2022 average of $94.90 per Bbl. In addition, the average domestic onshore rig count for the United States and Canada was 765 rigs reported in the fourth quarter of 2024, down from the average in the fourth quarter of 2023 of 781, according to a report from Baker Hughes.

Previous wording

Improved drilling economics from horizontal drilling and greater rig efficiencies. Unconventional resources are increasingly being targeted through the use of horizontal drilling. According to Baker Hughes, as reported on January 26, 2024, horizontal rigs accounted for approximately 90% of all rigs drilling in the United States and Canada, up from 77% as of December 26, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. Today the majority of E&P drilling is on multi-well pad development, allowing efficient drilling of multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Lium Research, has dropped from 28 days in 2014 to 18 days in 2023.

Current wording

Improved drilling economics from horizontal drilling and greater rig efficiencies. According to Baker Hughes, as reported on January 24, 2025, horizontal rigs accounted for approximately 90% of all rigs drilling in the United States and Canada, up from 77% as of December 26, 2014. Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. Today the majority of E&P drilling is on multi-well pad development, allowing efficient drilling of multiple horizontal wellbores from the same pad or location. The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Lium Research, has dropped from 28 days in 2014 to 16 days in 2024.

Previous wording

Increased complexity and service intensity of horizontal well completions. In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of frac stages and/ or the number of perforation clusters (frac initiation points) has also increased. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Liberty’s FracTrends database, from six million pounds per well in 2014 to over 20 million pounds per well in 2023. Further efficiency gains are being sought via the “simul-frac,” “trimul-frac,” and other techniques. When compared to typical zipper-frac operations, these methods allow operators to complete a pad of wells quicker, thereby shortening the time from spud to first production.

Current wording

Increased complexity and service intensity of horizontal well completions. In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of frac stages and/or the number of perforation clusters (frac initiation points) has also increased. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Liberty’s FracTrends database, from six million pounds per well in 2014 to roughly 22 million pounds per well in 2024. Further efficiency gains are being sought via the “simul-frac,” “trimul-frac,” and other techniques. When compared to typical zipper-frac operations, these methods allow operators to complete a pad of wells quicker, thereby shortening the time from spud to first production.

Previous wording

Our hydraulic fracturing and wireline services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing stage varies depending on the actual volumes and types of proppants, chemicals, and fluid utilized for each fracturing stage. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages.

Current wording

Our hydraulic fracturing and wireline services are performed in sections, which we refer to as fracturing stages. The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design. We primarily recognize revenue based on pump hours, fracturing stages, or days on location, although total revenue depends on the actual volumes and types of proppants, chemicals, and fluid utilized on each pad. The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages.

Previous wording

Cost of services (excluding depreciation, depletion, and amortization) increased $200.3 million, or 6%, to $3.3 billion for the year ended December 31, 2023 compared to $3.1 billion for the year ended December 31, 2022. The increase in expense was primarily related to increases in materials and parts consumption and higher labor costs related to reactivated fleets and higher fleet efficiency during the year ended December 31, 2023.

Current wording

Cost of services (excluding depreciation, depletion, and amortization) decreased $148.9 million, or 4%, to $3.2 billion for the year ended December 31, 2024 compared to $3.3 billion for the year ended December 31, 2023. The decrease in expense was primarily related to decreases in materials costs and lower repairs and maintenance costs, partially offset by increased personnel costs related to higher activity levels discussed above, during the year ended December 31, 2024.

Previous wording

Depreciation, depletion, and amortization expense increased $98.5 million, or 30%, to $421.5 million for the year ended December 31, 2023 compared to $323.0 million for the year ended December 31, 2022. The increase in 2023 was due to additional equipment placed in service not fully reflected in the prior year, including the deployment of our digiTechnologies SM.

Current wording

Depreciation, depletion, and amortization expense increased $83.5 million, or 20%, to $505.1 million for the year ended December 31, 2024 compared to $421.5 million for the year ended December 31, 2023. The increase in 2024 was due to additional equipment placed in service since the prior year period, including equipment related to the deployment of our digiTechnologies SM.

Previous wording

The Company recorded a gain on disposal of assets, net of $7.0 million for the year ended December 31, 2023 compared to $4.6 million for the year ended December 31, 2022. The gain recognized in the year ended December 31, 2023 was primarily the result of the Company selling used field equipment and light duty trucks in a strong used vehicle and equipment market. The gain recognized in the year ended December 31, 2022 was a result of the sale of used field equipment and light duty trucks in a strong used vehicle and equipment market offset by a loss on sale of two non-strategic facilities acquired in a previous acquisition and a loss on plan of sale for two other non-strategic facilities.

Current wording

The Company recorded a gain on disposal of assets, net of $5.3 million for the year ended December 31, 2024 compared to $7.0 million for the year ended December 31, 2023. The gain recognized in the year ended December 31, 2024 was primarily related to the disposal of used older technology field equipment that was no longer operational. The gain recognized in the year ended December 31, 2023 was a result of the Company selling used field equipment and light duty trucks in a strong used vehicle and equipment market.

Previous wording

The Company recognized income tax expense of $178.5 million for the year ended December 31, 2023, an effective rate of 24.3%, compared to an income tax benefit of $0.8 million, an effective rate of (0.2)%, recognized for the year ended December 31, 2022. The increase in income tax expense was primarily attributable to the Company recording taxes on the Company’s U.S. activity during the year ended December 31, 2023, compared to the release of a valuation allowance on its U.S. net deferred tax assets during the year ended December 31, 2022 largely offsetting taxes on 2022 activity.

Current wording

The Company recognized income tax expense of $87.3 million for the year ended December 31, 2024, an effective rate of 21.6%, compared to $178.5 million, for the year ended December 31, 2023, an effective rate of 24.3%. The decrease in income tax expense was primarily attributable to the decrease in net income before income taxes and increased U.S. federal tax credits.

Previous wording

We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income before interest, income taxes, and depreciation, depletion, and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock-based compensation, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, bad debt reserves, transaction, severance, and other costs, the gain or loss on remeasurement of liability under our tax receivable agreements, the gain or loss on investments, and other non-recurring expenses that management does not consider in assessing ongoing performance.

Current wording

We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income before interest, income taxes, and depreciation, depletion, and amortization. We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock-based compensation, new fleet or new basin start-up costs, fleet lay-down costs, gain or loss on the disposal of assets, net, bad debt reserves, transaction and other costs, the gain or loss on remeasurement of liability under our tax receivable agreements, the unrealized gain or loss on investments, net, and other non-recurring expenses that management does not consider in assessing ongoing performance.

Previous wording

Our board of directors, management, investors, and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them 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, depletion, and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP.

Current wording

Our Board, management, investors, and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them 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, depletion, and amortization) and other items that impact the comparability of financial results from period to period. We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP.

Previous wording

EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures 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 an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA 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.

Current wording

EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations. Net income is the GAAP financial measure most directly comparable to EBITDA and Adjusted EBITDA. Our non-GAAP financial measures 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 an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA 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.

Previous wording

EBITDA was $1.2 billion for the year ended December 31, 2023 compared to $745.3 million for the year ended December 31, 2022. Adjusted EBITDA was $1.2 billion for the year ended December 31, 2023 compared to $860.3 million for the year ended December 31, 2022. The increases in EBITDA and Adjusted EBITDA primarily resulted from increased activity levels in 2023 as described above under the captions Revenue, Cost of Services, and General and Administrative Expenses for the Year Ended December 31, 2023, Compared to Year Ended December 31, 2022.

Current wording

EBITDA was $940.5 million for the year ended December 31, 2024 compared to $1.2 billion for the year ended December 31, 2023. Adjusted EBITDA was $921.6 million for the year ended December 31, 2024 compared to $1.2 billion for the year ended December 31, 2023. The decreases in EBITDA and Adjusted EBITDA primarily resulted from lower pricing and partially offset by changes in activity levels in 2024 as described above under the captions Revenue, Cost of Services, and General and Administrative Expenses for the Year Ended December 31, 2024, Compared to Year Ended December 31, 2023.

Previous wording

Our primary sources of liquidity consist of cash flows from operations and borrowings under our ABL Facility. We expect to fund operations and organic growth with these sources. We monitor the availability and cost of capital resources such as equity and debt financings that could be leveraged for current or future financial obligations including those related to acquisitions, capital expenditures, working capital, and other liquidity requirements. We may incur additional indebtedness or issue equity in order to meet our capital expenditure activities and liquidity requirements, as well as to fund growth opportunities that we pursue, including via acquisition. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades, as well as the repurchases of, and dividends on, shares of our Class A Common Stock.

Current wording

Our primary sources of liquidity consist of cash flows from operations and borrowings under our ABL Facility (as defined below). We believe that we can fund operations and current organic growth plans with these sources. We monitor the availability and cost of capital resources such as equity, debt, and lease financings that could be leveraged for current or future financial obligations including those related to acquisitions, capital expenditures, working capital, and other liquidity requirements. We may incur additional indebtedness or issue equity in order to meet our capital expenditure activities and liquidity requirements, as well as to fund organic and other growth opportunities that we pursue, including via acquisition. Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades, as well as the repurchases of, and dividends on, shares of our Class A Common Stock.

Previous wording

Cash and cash equivalents decreasedby $6.9 million to $36.8 million as of December 31, 2023 compared to $43.7 million as of December 31, 2022, while working capital excluding cash and current liabilities under debt and lease arrangements increased $42.2 million.

Current wording

Cash and cash equivalents decreasedby $16.8 million to $20.0 million as of December 31, 2024 compared to $36.8 million as of December 31, 2023, while working capital excluding cash and current liabilities under debt and lease arrangements decreased $88.2 million.

Previous wording

As of December 31, 2023, we had $525.0 million committed under the ABL Facility, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory available to finance working capital needs. As of December 31, 2023, the borrowing base was calculated to be $420.3 million, and the Company had $140.0 million outstanding, in addition to a letter of credit in the amount of $2.6 million, with $277.7 million of remaining availability.

Current wording

As of December 31, 2024, the Company had $525.0 million committed under the ABL Facility, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory available to finance working capital needs. As of December 31, 2024, the borrowing base was calculated to be $319.8 million, and the Company had $190.5 million outstanding, in addition to letters of credit totaling $14.0 million, with $115.3 million of remaining availability.

Previous wording

Additionally, on January 23, 2023, the Company borrowed $106.7 million on the ABL Facility and used the proceeds to pay off and and terminate the Term Loan Facility. The amount paid included the balance of the Term Loan Facility upon payoff of $104.7 million, $0.9 million of accrued interest, and a $1.1 million prepayment premium. Additionally, there were $0.2 million in administrative agent and lender legal fees included in the pay off.

Current wording

Additionally, on January 23, 2023, the Company borrowed $106.7 million on the ABL Facility and used the proceeds to pay off and terminate the Term Loan Facility. The amount paid included the balance of the Term Loan Facility upon payoff of $104.7 million, $0.9 million of accrued interest, and a $1.1 million prepayment premium. Additionally, there were $0.2 million in administrative agent and lender legal fees included in the pay off.

Previous wording

Under our share repurchase program, the Company was initially authorized to repurchase up to $250.0 million of outstanding Class A Common Stock through and including July 31, 2024. On January 24, 2023, the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $500.0 million. Furthermore, on January 23, 2024, the Board authorized and the Company announced an increase to the share repurchase program that increased the Company’s cumulative repurchase authorization to $750.0 million and extended the authorization through July 31, 2026. Shares may be repurchased from time to time for cash in the open market transactions, through block trades, in privately negotiated transactions, through derivative transactions or by other means in accordance with applicable federal securities laws. The timing and the amount of repurchases will be determined by the Company at its discretion based on an evaluation of market conditions, capital allocation alternatives and other factors. The share repurchase program does not require us to purchase any dollar amount or number of shares of our Class A Common Stock and may be modified, suspended, extended or terminated at any time without prior notice. The Company expects to fund any repurchases by using cash on hand, borrowings under its revolving credit facility and expected free cash flow to be generated through the duration of the share repurchase program. During the year ended December 31, 2023, the Company repurchased and retired shares of Class A Common Stock for $203.1 million, under the share repurchase program.

Current wording

Under our share repurchase program, the Company is authorized to repurchase up to $750.0 million of outstanding Class A Common Stock through and including July 31, 2026. Shares may be repurchased from time to time for cash in open market transactions, through block trades, in privately negotiated transactions, through derivative transactions, or by other means in accordance with applicable federal securities laws. The timing and the amount of repurchases will be determined by the Company at its discretion based on an evaluation of market conditions, capital allocation alternatives and other factors. The share repurchase program does not require us to purchase any dollar amount or number of shares of our Class A Common Stock and may be modified, suspended, extended or terminated at any time without prior notice. The Company expects to fund any repurchases by using cash on hand, borrowings under the ABL Facility, and expected free cash flow to be generated through the duration of the share repurchase program. During the year ended December 31, 2024, the Company repurchased and retired shares of Class A Common Stock for $127.4 million, under the share repurchase program.

Previous wording

Operating Activities. Net cash provided by operating activities was $1.0 billion for the year ended December 31, 2023, compared to $530.4 million for the year ended December 31, 2022. The $484.2 million increase in cash from operating activities is primarily attributable to a $598.7 million increase in revenues, offset by a $280.7 million increase in cash operating expenses, interest expense, net, and income tax, and a $111.7 million decrease in cash from changes in working capital for the year ended December 31, 2023, compared to a $277.9 million decrease in cash from changes in working capital for the year ended December 31, 2022.

Current wording

Operating Activities. Net cash provided by operating activities was $829.4 million for the year ended December 31, 2024, compared to $1.0 billion for the year ended December 31, 2023. The $185.2 million decrease in cash from operating activities is primarily attributable to a $432.8 million decrease in revenues, offset by a $145.3 million decrease in cash operating expenses, interest expense, net, and income tax expense, and a $9.4 million decrease in cash from changes in working capital for the year ended December 31, 2024, compared to a $111.7 million decrease in cash from changes in working capital for the year ended December 31, 2023.

Previous wording

Investing Activities. Net cash used in investing activities was $672.3 million for the year ended December 31, 2023, compared to $450.7 million for the year ended December 31, 2022. Cash used in investing activities was higher during the year ended December 31, 2023, compared to the year ended December 31, 2022 as the Company continued to invest in equipment, including the new digiTechnologies SM suite, to support increased customer demand in next generation equipment and technology. Additionally, during the year ended December 31, 2023, the Company acquired Siren for $75.7 million in cash, net of cash received and normal post-closing matters, refer to Note 3—Acquisitions to the consolidated financial statements in Part II, Item 8 of this Annual Report for additional information related to the Siren Acquisition.

Current wording

Investing Activities. Net cash used in investing activities was $643.1 million for the year ended December 31, 2024, compared to $672.3 million for the year ended December 31, 2023. Cash used in investing activities was lower during the year ended December 31, 2024, compared to the year ended December 31, 2023 primarily due to the Siren Acquisition and higher equity investments in the prior year period, offset by higher capital spending in the current year period, and lower proceeds from asset sales. The Company purchased Siren Energy for $75.7 million in cash, net of cash received, during the year ended December 31, 2023. Refer to Note 3—Acquisitions to the consolidated financial statements in Part II, Item 8 of this Annual Report for additional information related to the Siren Acquisition. Investments in equipment, including the new digiTechnologies SMsuite and capitalized maintenance of existing equipment increased $47.7 million, from $603.3 million for the year ended December 31, 2023 to $651.0 million for the year ended December 31, 2024. Proceeds from asset sales decreased $2.9 million, from $26.9 million to $24.0 million as the Company benefited from strong used vehicle and equipment markets in the prior period. Finally, during the year ended December 31, 2024, the Company invested $16.1 million for equity investments in Tamboran Resources Corporation, Empire Energy Group Ltd., and Falcon Oil & Gas Ltd, compared to $20.3 million for equity investments in Tamboran Resources Corporation and Oklo Inc. during the year ended December 31, 2023.

Previous wording

Our material cash commitments consist primarily of obligations under long-term debt, TRAs, finance and operating leases for property and equipment, cash used to pay for repurchases of, and dividends on, shares of our Class A Common Stock, and purchase obligations as part of normal operations. Certain amounts included in our contractual obligations as of December 31, 2023 are based on our estimates and assumptions about these obligations, including pricing, volumes and duration. We have no material off balance sheet arrangements as of December 31, 2023, except for purchase commitments under supply agreements disclosed below.

Current wording

Our material cash commitments consist primarily of obligations under long-term debt on the ABL Facility, TRAs, finance and operating leases for property and equipment, cash used to pay for repurchases of, and dividends on, shares of our Class A Common Stock, and purchase obligations as part of normal operations. Certain amounts included in our contractual obligations as of December 31, 2024 are based on our estimates and assumptions about these obligations, including pricing, volumes, and duration. We have no material off balance sheet arrangements as of December 31, 2024, except for purchase commitments under supply agreements disclosed below.

Previous wording

During the year ended December 31, 2023, the Company expanded certain equipment lease facilities and entered into a new equipment lease facility with an additional lessor resulting in new finance lease obligations of $160.5 million. The term on these new leases range from two to five years. The Company had finance lease obligations of $51.1 million payable within the next twelve months and $151.6 million payable thereafter.

Current wording

During the year ended December 31, 2024, the Company expanded its equipment lease facilities resulting in the addition of $149.0 million in new finance lease obligations. The term on these new leases range from three to five years. As of December 31, 2024, the Company had finance lease obligations of $87.5 million payable within the next twelve months and $222.5 million payable thereafter. Included in those liabilities, the Company had expected cash payments for estimated interest on our finance lease obligations of $17.1 million payable within the next twelve months and $22.4 million payable thereafter.

Previous wording

On January 23, 2023, the Company borrowed $106.7 million on the ABL Facility and used the proceeds to pay off and terminate the Term Loan Facility. The balance of the Term Loan Facility at pay off was $104.7 million and included $0.9 million of accrued interest, and a $1.1 million prepayment premium. As such, the only outstanding debt facility as of December 31, 2023 was the ABL Facility.

Current wording

On January 23, 2023, the Company borrowed $106.7 million on the ABL Facility and used the proceeds to pay off and terminate the Term Loan Facility. The balance of the Term Loan Facility at pay off was $104.7 million and included $0.9 million of accrued interest, and a $1.1 million prepayment premium. As such, the only outstanding debt facility as of December 31, 2024 and 2023 was the ABL Facility.

Previous wording

As of December 31, 2023, the Company has purchase obligations of $143.9 million payable within the next twelve months and $13.0 million payable thereafter. See Note 15—Commitments & Contingencies to theconsolidated financial statements in Part II, Item 8 of this Annual Report for information regarding scheduled contractual obligations.

Current wording

As of December 31, 2024, the Company has purchase obligations of $26.3 million payable within the next twelve months. See Note 15—Commitments & Contingencies to theconsolidated financial statements in Part II, Item 8 of this Annual Report for information regarding scheduled contractual obligations.

Previous wording

As of December 31, 2023, the Company expects to make a $5.2 million payment under the TRAs within the next twelve months. Future amounts payable under the TRAs are dependent upon future events. See Note 12—Income Taxes to theconsolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding the TRAs.

Current wording

As of December 31, 2024, the Company expects to make a $40.8 million payment under the TRAs within the next twelve months. Future amounts payable under the TRAs are dependent upon future events. See Note 12—Income Taxes to theconsolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding the TRAs.

Previous wording

The Company is a corporation and is subject to U.S. federal, state, and local income tax on its share of Liberty LLC’s taxable income. The Company is also subject to Canada federal and provincial income tax on its foreign operations.

Current wording

The Company is a corporation and is subject to U.S. federal, state, and local income tax. The Company is also subject to Canada and Australia federal and provincial income tax on its foreign operations.

Previous wording

The effective global income tax rate applicable to the Company for the year ended December 31, 2023 was 24.3% compared to (0.2)% for the year ended December 31, 2022. The Company’s effective tax rate is greater than the statutory federal income tax rate of 21.0% due to the Company’s Canadian operations, state income taxes in the states the Company operates, as well as nondeductible executive compensation. For 2022, the Company’s effective tax rate was less than the statutory federal income tax rate due to the Company releasing the valuation allowance recorded in a previous year on its U.S. net deferred tax assets as of December 31, 2022, primarily due to entering into a three-year cumulative pre-tax book income position and improved operating results.

Current wording

The effective global income tax rate applicable to the Company for the year ended December 31, 2024 was 21.6% compared to 24.3% for the year ended December 31, 2023. The Company’s effective tax rate for both years is greater than the statutory federal income tax rate of 21.0% due to the Company’s Canadian operations, state income taxes in the states the Company operates, as well as nondeductible executive compensation, partially offset by U.S. federal income tax credits.

Previous wording

The Company recognized income tax expense of $178.5 million and an income tax benefit of $0.8 million for the years ended December 31, 2023 and 2022, respectively. The Company’s effective tax rate can be volatile and may change with, among other things, the amount of jurisdiction pre-tax income or loss, ability to utilize foreign tax credits, excess tax benefits or deficiencies from share-based compensation and changes in tax laws in the jurisdictions that we operate.

Current wording

The Company recognized income tax expense of $87.3 million and $178.5 million for the years ended December 31, 2024 and 2023, respectively. The Company’s effective tax rate can be volatile and may change with, among other things, the amount of jurisdiction pre-tax income or loss, ability to utilize foreign tax credits, excess tax benefits or deficiencies from share-based compensation and changes in tax laws in the jurisdictions that we operate.

Previous wording

Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial reporting and tax bases of assets and liabilities, and are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. In the year ended December 31, 2023, the Company’s net deferred tax liabilities were $102.3 million. The Company has not recorded a valuation allowance against the deferred tax assets for the year ended December 31, 2023.

Current wording

Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial reporting and tax bases of assets and liabilities, and are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. In the year ended December 31, 2024, the Company’s U.S. net deferred tax liabilities were $137.7 million and Canada net deferred tax assets were $1.5 million. The Company has no valuation allowances recorded against the deferred tax assets for the year ended December 31, 2024 and 2023.