Item 7. Management’s Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors.” Except as required by law, we assume no obligation to update any of these forward-looking statements. This section of this Annual Report generally discusses 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. For discussion of year ended December 31, 2022, as well as the year ended 2023 compared to the year ended December 31, 2022, refer to Part II, Item 7— Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2023 Annual Report.
Overview
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.
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.
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.
34
Recent Trends and Outlook
Moderate declines in frac activity, that started in 2023, continued throughout 2024. However, the market appears to have reached an inflection point in early 2025 as completions activity emerges from 2024 lows. In 2025, E&P operators, especially those with an oil exploration focus, are working to maintain production levels from 2024. Improving natural gas fundamentals are encouraging as well. For the full year, industry-wide lateral footage completed is expected to be approximately flat with 2024.
The slowing pace of activity in late 2024 resulted in near term price pressure to start 2025, most notably impacting conventional fleets. The fundamental outlook for next generation, higher quality fleets remains strong, as operators continue to demand technologies that provide significant emissions reductions, fuel savings, and operational efficiency advantages. The growing complexities of E&P demands and the continued drive for efficiency gains promote continued investment in technology and partnering with high quality service companies.
Global oil markets reflect ongoing uncertainties in geopolitics, Chinese economic growth, OPEC+ production plans, and a change in the domestic political climate, but the resulting commodity price fluctuation has not led to a meaningful change in E&P activity plans. Natural gas demand is supported by LNG export capacity expansion and a large projected multi-year increase in North American power consumption.
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.
Acquisitions
On April 6, 2023, LPI accelerated its expansion by acquiring Siren, a Permian focused integrated natural gas compression and CNG delivery business with 16 MMcf per day of natural gas compression capacity at two expandable Permian sites and transportation, logistics, and pressure reduction services, for cash consideration of $75.7 million, after post-closing adjustments and net of cash received. LPI currently delivers fuel to customers in both the drilling and completions markets, and its logistics system is designed to deliver CNG, renewable natural gas, or hydrogen to remote locations. We believe that the added natural gas compression capability is a key enabler of the next step of cost and emissions reductions in the industry.
Increase in Drilling Efficiency and Service Intensity of Completions
Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe that well economics have improved, and unconventional oil and gas production is globally competitive. Liberty has been a significant partner with our customers in driving these continued improvements.
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.
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
35
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.
These industry trends continue to keep our customers as important suppliers to the global oil and natural gas markets, which directly benefit hydraulic fracturing companies like us that have the expertise and innovative technology to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions. Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue.
Recent Leadership Updates
On February 3, 2025, Christopher A. Wright, our Chief Executive Officer and Chairman of the Board, was confirmed to the position of Secretary of Energy of the United States and resigned from his positions as Chairman of the Board, Director, and Chief Executive Officer of the Company. Also, on February 3, 2025, in accordance with the Company’s succession plan, the Board appointed William Kimble as the non-executive Chairman of the Board and Ron Gusek as the Company’s Chief Executive Officer and Director. Lastly, on January 22, 2025, the Board approved an increase to the size of the Board from nine to 10 directors and appointed Arjun Murti to fill the newly created vacancy.
How We Generate Revenue
We currently generate revenue through the provision of hydraulic fracturing, wireline services and goods, including sand from our Permian Basin sand mines, proppant delivery and logistics, and natural gas compression and delivery. These services and goods are provided under a variety of contract structures, primarily master service agreements (“MSAs”) as supplemented by statements of work, pricing agreements and specific quotes. A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to approximately one year in length. However, the majority of those agreements provide for pricing adjustments based on market conditions. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer.
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.
Costs of Conducting Our Business
The principal expenses involved in conducting our business are direct cost of personnel, services, and materials used in the provision of services, general and administrative expenses, and depreciation, depletion, and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation, depletion, and amortization, based on several factors, including industry conditions and expected demand for our services.
How We Evaluate Our Operations
We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost, of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following:
• Revenue;
• Operating Income;
• Net Income;
• EBITDA; and
• Adjusted EBITDA;
Revenue
We analyze our revenue by comparing actual revenue to our internal projections for a given period and to prior periods to assess our performance.
36
Operating Income
We analyze our operating income, which we define as revenues less direct operating expenses, depreciation, depletion, and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods.
Net Income
We analyze our net income, which we define as operating income adjusted for other income or expense, net, including interest expense, net, and income tax expense. We analyze net income by comparing actual net income to our internal projections for a given period and to prior periods to assess our performance.
EBITDA and Adjusted EBITDA
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, provision for credit losses, 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. See “Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income, the most comparable financial measures calculated and presented in accordance with GAAP.
Results of Operations
Year Ended December 31, 2024, Compared to Year Ended December 31, 2023
Years Ended December 31,
Description 2024 2023 Change
(in thousands)
Revenue $ 4,315,161 $ 4,747,928 $ (432,767)
Cost of services, excluding depreciation, depletion, and amortization shown separately 3,200,506 3,349,370 (148,864)
General and administrative 225,474 221,406 4,068
Transaction and other costs — 2,053 (2,053)
Depreciation, depletion, and amortization 505,050 421,514 83,536
Gain on disposal of assets, net (5,337) (6,994) 1,657
Operating income 389,468 760,579 (371,111)
Other (income) expense, net (13,803) 25,689 (39,492)
Net income before income taxes 403,271 734,890 (331,619)
Income tax expense 87,261 178,482 (91,221)
Net income 316,010 556,408 (240,398)
Less: Net income attributable to non-controlling interests — 91 (91)
Net income attributable to Liberty Energy Inc. stockholders $ 316,010 $ 556,317 $ (240,307)
Revenue
Our revenue decreased $432.8 million, or 9%, to $4.3 billion for the year ended December 31, 2024 compared to $4.7 billion for the year ended December 31, 2023. The decrease in revenue was primarily attributable to a decrease in service and materials pricing, partially offset by higher activity levels primarily from increased fleet efficiency.
Cost of Services
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.
General and Administrative
General and administrative expenses increased $4.1 million, or 2%, to $225.5 million for the year ended December 31, 2024 compared to $221.4 million for the year ended December 31, 2023 primarily related to increased corporate costs to
37
support our additional service offerings, partially offset by a decrease in cash incentive and stock-based compensation expense due to lower operating results compared to the prior year period.
Transaction and Other Costs
Transaction and other costs decreased $2.1 million, or 100%, as the Company did not incur such costs for the year ended December 31, 2024 compared to $2.1 million for the year ended December 31, 2023. The costs incurred during the year ended December 31, 2023 primarily consisted of due diligence and integration costs for the Siren Acquisition. See Note 3—Acquisitions to the consolidated financial statements included in Part II, Item 8 of this Annual Report for further details.
Depreciation, Depletion, and Amortization
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 .
Gain on Disposal of Assets, net
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.
Other (Income) Expense, net
Other (income) expense, net changed by $39.5 million to $13.8 million income for the year ended December 31, 2024 compared to $25.7 million expense during the year ended December 31, 2023. Other (income) expense, net is comprised of loss on remeasurement of liability under the TRAs of $3.2 million during the year ended December 31, 2024, compared to a gain of $1.8 million for the year ended December 31, 2023. It also includes an unrealized gain on investments, net of $49.2 million related to investments in equity securities measured at fair value during the year ended December 31, 2024, compared to $0 for the year ended December 31, 2023. Interest expense, net increased $3.2 million primarily as a result of the addition of finance lease liabilities, refer to “Liquidity and Capital Resources” below for further discussion of the Company’s finance leases. Additionally, interest income—related party decreased $1.5 million related to a note receivable agreement executed in December 2022, amended in August 2023, and fully collected in March 2024.
Income Tax Expense
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.
Comparison of Non-GAAP Financial Measures
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.
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.
38
Note Regarding Non-GAAP Financial Measures
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.
The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income, which is the most directly comparable GAAP financial measure for the periods presented:
Year Ended December 31, 2024, Compared to Year Ended December 31, 2023: EBITDA and Adjusted EBITDA
Years Ended December 31,
Description 2024 2023 Change
(in thousands)
Net income $ 316,010 $ 556,408 $ (240,398)
Depreciation, depletion, and amortization 505,050 421,514 83,536
Interest expense, net 32,214 27,506 4,708
Income tax expense 87,261 178,482 (91,221)
EBITDA $ 940,535 $ 1,183,910 $ (243,375)
Stock-based compensation expense 32,412 33,026 (614)
Gain on disposal of assets, net (5,337) (6,994) 1,657
Unrealized gain on investments, net (49,227) — (49,227)
Loss (gain) on remeasurement of liability under tax receivable agreements 3,210 (1,817) 5,027
Provision for credit losses — 808 (808)
Transaction and other costs — 2,053 (2,053)
Fleet start-up and lay-down costs — 2,082 (2,082)
Adjusted EBITDA $ 921,593 $ 1,213,068 $ (291,475)
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 .
Liquidity and Capital Resources
Overview
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.
Cash and cash equivalent s decreased by $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.
39
On September 19, 2017, the Company entered into two credit agreements, (i) a revolving line of credit up to $250.0 million, subsequently increased to $525.0 million, see below, (the “ABL Facility”) and (ii) a $175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”).
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.
On January 23, 2023, the Company entered into an Eighth Amendment to the ABL Facility (the “Eighth ABL Amendment”). The Eighth ABL Amendment amends certain terms, provisions and covenants of the ABL Facility, including, among other things: (i) increasing the maximum revolver amount from $425.0 million to $525.0 million (the “Upsized Revolver”); (ii) increasing the amount of the accordion feature from $75.0 million to $100.0 million; (iii) extending the maturity date from October 22, 2026 to January 23, 2028; (iv) modifying the dollar amounts of various credit facility triggers and tests proportionally to the Upsized Revolver; (v) permitting repayment under the Term Loan Facility prior to February 10, 2023; and (vi) increasing certain indebtedness, intercompany advance, and investment baskets. The Eighth ABL Amendment also includes an agreement from Wells Fargo Bank, National Association, as administrative agent, to release its second priority liens and security interests on all collateral that served as first priority collateral under the Term Loan Facility. This release was completed during the three months ended June 30, 2023.
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.
The ABL Facility contains covenants that restrict our ability to take certain actions. At December 31, 2024, we were in compliance with all debt covenants.
See Note 8 —Debt to the consolidated financial statements included in Part II, Item 8 of this Annual Report for further details.
We have no material off balance sheet arrangements as of December 31, 2024, except for purchase commitments under supply agreements as disclosed below under Note 15—Commitments & Contingencies in Part II, Item 8 of this Annual Report. As such, we are not materially exposed to any other financing, liquidity, market, or credit risk that could arise if we had engaged in such financing arrangements.
Share Repurchase Program
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.
40
Cash Flows
The following table summarizes our cash flows for the periods indicated:
Years Ended December 31,
Description 2024 2023 Change
(in thousands)
Net cash provided by operating activities
$ 829,374 $ 1,014,583 $ (185,209)
Net cash used in investing activities
(643,113) (672,328) 29,215
Net cash used in financing activities
(202,705) (349,315) 146,610
Analysis of Cash Flow Changes Between the Years Ended December 31, 2024 and December 31, 2023
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.
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 SM suite 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.
Financing Activities . Net cash used in financing activities was $202.7 million for the year ended December 31, 2024, compared to $349.3 million for the year ended December 31, 2023. The $146.6 million decrease in cash used in financing activities was primarily due to net borrowings of $50.5 million during the current year period compared to $79.7 million in net repayment of borrowings during the prior year as well as a $73.9 million decrease in share repurchases for the year ended December 31, 2024, compared to the year ended December 31, 2023. These decreases in cash used in financing activities were offset by a $32.9 million increase in cash paid for finance leases, a $10.5 million increase in cash tax withholding on restricted stock unit vestings, and a $10.6 million increase in dividends paid.
41
Cash Requirements
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.
See Note 8 —Debt to the consolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding scheduled maturities of our long-term debt. See Note 6 —Leases to the consolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding scheduled maturities of finance and operating leases.
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.
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.
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 the consolidated financial statements in Part II, Item 8 of this Annual Report for information regarding scheduled contractual obligations.
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 No te 12 —Income Taxes to the consolidated financial statements included in Part II, Item 8 of this Annual Report for information regarding the TRAs.
There have been no other material changes to cash requirements during the year ended December 31, 2024.
Other Factors Affecting Liquidity
Customer receivables: In line with industry practice, we typically bill our customers for services provided in arrears dependent upon contractual terms. In weak economic environments, we may experience delays in collection from our customers. In the past, we have experienced delays in customer payments and periodically agreed to extended payment terms, however, we have not experienced any material non-payment events.
Tax Receivable Agreements
In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually recognizes (or is deemed to recognize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holders’ Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right of each Liberty Unit Holder (the “Redemption Right”), subject to certain limitations, to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (A) shares of our Class A Common Stock at the specific redemption ratio or (B) an equivalent amount of cash, or, upon the exercise of the Redemption Right, the right of the Company (instead of Liberty LLC) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder (the “Call Right”) for, at its election, (1) one share of Class A Common Stock or (2) an equivalent amount of cash, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs. On January 31, 2023, the last redemption of the Liberty LLC Units occurred.
42
With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standard Codification (“ASC”) Topic 450, Contingencies (“ASC Topic 450”).
If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs.
Income Taxes
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.
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.
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.
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.
Refer to Note 12— Income Taxes to the consolidated financial statements in Part II, Item 8 of this Annual Report for additional information related to income tax expense.
Critical Accounting Policies and Estimates
The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations.
We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in Part II, Item 8 of this Annual Report.
Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract change, our revenue and / or costs under that contract may change. In connection with ASC Topic 842 - Leases (“Topic 842”), the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and service component for certain of the Company’s service contracts when the service component is the predominant component and continues to account for the combined component under ASC Topic 606 - Revenue from Contracts with Customers .
Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course
43
of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment.
Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology.
We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset.
Impairment of long-lived assets: Long-lived assets, such as property and equipment, right-of-use lease assets and intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Possible indicators of impairment may include events or changes in circumstances affecting the manner in which the assets are being used, historical and estimated future profitability measures, and other adverse events or changes that could affect the value of the assets. If a triggering event is identified, recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment. If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future.
Leases: In accordance with ASC Topic 842, Leases , the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew; however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception.
Tax Receivable Agreements: In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies .
Share Repurchases: The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A Common Stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero. Thereafter, any excess purchase price will be recorded as a reduction to retained earnings. All Class A Common Stock shares repurchased to date have been retired upon repurchase.
44