What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-02 compared with 2025-02-06 · 112 added, 110 removed, 237 unchanged (48% of the section changed)

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For discussion of year ended December 31, 2023, as well as the year ended 2024 compared to the year ended December 31, 2023, refer to Part II, Item 7— Management’s Discussion and Analysis of Financial Condition and Results of Operations of our 2024 Annual Report.

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.

The Company, together with its subsidiaries, is a leading integrated energy services and technology company, and one of the largest providers of innovative completions services and related technologies to onshore oil, natural gas, and enhanced geothermal exploration and production (“E&P”) companies.

We offer customers completions services, which include hydraulic fracturing together with complementary services including wireline services, proppant delivery solutions, field gas processing and treating, compressed natural gas (“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, 2025.

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 provide our services primarily in the major oil and gas shale basins in North America and in the Northern Territory of Australia.

We also own and operate Liberty Power Innovations LLC (“LPI”), providing advanced distributed power and energy storage solutions, serving the commercial and industrial, data center, energy and mining industries.

LPI was formed with the initial focus on supporting Liberty’s transition towards our next generation digiFleets℠ and dual fuel fleets, by providing consistent and reliable power generation solutions and natural gas fueling services, which are critical to maintaining highly efficient well site operations.

In January 2025, we announced LPI’s expansion into the distributed power business.

On March 3, 2025, we completed the acquisition of IMG Energy Solutions (“the IMG Acquisition”), a leading developer of distributed power systems, for cash consideration of approximately $19.6 million, subject to normal closing adjustments and net of cash received.

The IMG Acquisition augmented our portfolio with advanced engineering, design, and development capabilities for the development of power systems, enhanced software control systems, power marketing and utility interconnection experience, and operations and maintenance experience.

During 2025, LPI was primarily focused on the planning and development of our power service platform to pursue projects supporting the power demand created by new data center development and other commercial and industrial applications.

LPI is in the process of expanding market awareness of its integrated power and fuel solutions offering, developing engineered solutions, and ordering equipment and long-lead time items for these expected projects.

LPI also expanded its natural gas fueling services to support larger scale distributed power installations.

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.

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(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.

(vi) our wet sand handling technology and piped sand slurry solution which eliminate the need to dry sand, enabling the deployment of mobile mines nearer to wellsites;

(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;

and (viii) a suite of internally developed software solutions incorporating advanced analytics to support operations, maintenance and logistics management.

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 during completions services jobs to better service our customers.

LPI’s technology platform for distributed power generation includes (a) the Forte SM solution, which uses a modular, standardized construction approach for generation sites to reduce the risk of project execution, (b) the Tempo SM power quality management system to manage high-amplitude, cyclical load variations associated with artificial intelligence workloads and (c)

when a grid interconnection is requested by the customer and available, the Chorus SM solution to optimize power costs through the use of a mix of co-located generation and grid power.

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.

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.

The convergence of AI-driven data center expansion, the onshoring of domestic manufacturing, and increased industrial electrification has created structural demand growth for power.

Underinvestment in grid infrastructure, transmission constraints, and evolving commercial realities and utility reforms, driven in part by public concerns, have catalyzed broader market recognition of the inherent strategic value of distributed power solutions.

Within North American oil and gas markets, conditions appear to have stabilized after a protracted period of softening activity, as the industry has largely adjusted to OPEC+ supply concerns and tariff-related volatility experienced in 2025.

Fourth quarter completions activity defied normal seasonal declines, surpassing expectations.

Completions demand is projected to hold firm in 2026.

We expect North American producers to respond to global oil and gas dynamics with flat oil production and modest growth in gas-directed activity.

Global oil markets are currently balancing a structural oil surplus, elevated geopolitical risk, and an OPEC+ production pause, keeping oil prices largely rangebound.

Natural gas markets are supported by significant expansion in LNG export capacity and multi-year growth in power consumption.

Industry fundamentals are expected to improve over time as supply-side dynamics gradually rebalance with completions demand.

Recent pricing pressures on completions services, combined with the slowdown in activity, have driven an acceleration in equipment cannibalization and attrition, while underinvestment in next generation technology has limited the replacement of lost capacity.

As the market recalibrated at the start of the year, fewer crews are available to meet any incremental completions demand.

E&Ps remain focused on harnessing efficiency gains and engineering solutions to lower the total cost per unit of energy, driving the bar higher for technologically superior services and operational success to achieve these results.

During the year 2025, the posted WTI price traded at an average of $65.45 per barrel (“Bbl”), as compared to the 2024 average of $76.63 per Bbl, and the 2023 average of $77.58 per Bbl.

In addition, in the year ending December 31, 2025, the Henry Hub price traded at an average of $3.51 per one million British thermal units (“MMBtu”) as compared to the year ending December 31, 2024 and 2023 average of $2.19 and $2.53 per MMBtu, respectively.

In addition, the average domestic onshore rig count for the United States and Canada was 709 rigs reported in the fourth quarter of 2025, down from the average in the fourth quarter of 2024 of 765, according to a report from Baker Hughes.

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.

The IMG Acquisition brings integrated capabilities across engineering design and development, construction management, enhanced software and monitoring systems, operations and marketing.

We believe the IMG Acquisition will strengthen LPI by incorporating IMG Energy Solutions’s advanced engineering designs, software control systems, utility interconnection experience and power marketing expertise.

Increase in Drilling Efficiency and Service Intensity of Completions

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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.

Today the majority of E&P drilling is on multi-well pad development, allowing efficient drilling of multiple horizontal wellbores from the same pad

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 2025.

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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.

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.

These industry trends continue to keep our customers as important suppliers to the global oil and natural gas markets, which directly benefit completions services 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.

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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.

On January 22, 2025, our 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.

Additionally, on August 26, 2025, Audrey Robertson resigned from the Board and was subsequently confirmed to the position of Assistant Secretary of Energy for Energy Efficiency and Renewable Energy at the Department of Energy.

On October 16, 2025, the Board appointed Ms.

Alice Yake to the vacancy created by Ms.

Robertson ’ s resignation.

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.

We currently generate revenue through the provision of completions services, including 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.

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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.

Our hydraulic fracturing 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.

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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.

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, net, provision for credit losses, transaction 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.

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Revenue $ 4,006,116 $ 4,315,161 $ (309,045)

Cost of services, excluding depreciation, depletion, and amortization shown separately 3,200,506 3,349,370 (148,864)

Costs of services (exclusive of depreciation, depletion, and amortization shown separately below) 3,168,109 3,200,506 (32,397)

General and administrative 247,436 225,474 21,962

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Depreciation, depletion, and amortization 500,332 505,050 (4,718)

Gain on disposal of assets, net (5,337) (6,994) 1,657

Loss (gain) on disposal of assets, net 16,691 (5,337) 22,028

Operating income 72,708 389,468 (316,760)

Other (income) expense, net (13,803) 25,689 (39,492)

Other income, net (122,483) (13,803) (108,680)

Net income before income taxes 195,191 403,271 (208,080)

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Net income 147,872 316,010 (168,138)

Net income attributable to non-controlling interests — 91 (91)

Net income attributable to Liberty Energy Inc.

stockholders $ 316,010 $ 556,317 $ (240,307)

Our revenue decreased $309.0 million, or 7%, to $4.0 billion for the year ended December 31, 2025 compared to $4.3 billion for the year ended December 31, 2024.

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.

The decrease in revenue was primarily attributable to a decrease in service and materials pricing, offset by moderately increased activity levels.

Costs of Services

Costs of services (exclusive of depreciation, depletion, and amortization) decreased $32.4 million, or 1%, to $3.2 billion for the year ended December 31, 2025 compared to $3.2 billion for the year ended December 31, 2024.

The decrease in expense was primarily related to decreases in materials costs and lower repairs and maintenance costs, partially offset by increased personnel costs.

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

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.

General and administrative expenses increased $22.0 million, or 10%, to $247.4 million for the year ended December 31, 2025 compared to $225.5 million for the year ended December 31, 2024 primarily attributable to increasing corporate costs and increased stock-based compensation expense recognized during the first quarter of 2025 in connection with the resignation of Christopher A.

Wright, the Company’s previous Chief Executive Officer and Chairman of the Board, from the Company upon his confirmation to the Secretary of Energy of the United States.

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.

Transaction and other costs was $0.8 million for the year ended December 31, 2025 compared to $0.0 million for the year ended December 31, 2024.

The Company incurred costs related to the IMG Acquisition in 2025, 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.

Depreciation, depletion, and amortization remained relatively flat, decreasing $4.7 million, or 1%, to $500.3 million for the year ended December 31, 2025 compared to $505.1 million for the year ended December 31, 2024.

Loss (Gain) on Disposal of Assets, net

The Company recorded a loss on disposal of assets, net of $16.7 million for the year ended December 31, 2025 compared to a gain, net of $5.3 million for the year ended December 31, 2024.

The loss recognized in the year ended December 31, 2025 was primarily related to the disposal of used older technology field equipment that was no longer operational as well as the write-off related to an insured loss for equipment damaged on location.

The gain recognized in the year ended December 31, 2024 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.

Other Income, net

The Company recognized other income, net of $122.5 million for the year ended December 31, 2025 compared to $13.8 million during the year ended December 31, 2024, an increase of $108.7 million.

Other (income) expense, net is comprised of gain on investments, net of $162.6 million related to investments in equity securities measured at fair value during the year ended December 31, 2025, compared to $49.2 million for the year ended December 31, 2024 and gain on remeasurement of liability under the TRAs of $0.1 million during the year ended December 31, 2025, compared to a loss of $3.2 million for the year ended December 31, 2024, offset by interest expense, net.

Interest expense, net increased $7.6 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.

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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.

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 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.

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Stock-based compensation expense 41,922 32,412 9,510

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

Loss (gain) on disposal of assets, net 16,691 (5,337) 22,028

Gain on investments, net (162,642) (49,227) (113,415)

(Gain) loss on remeasurement of liability under tax receivable agreements (147) 3,210 (3,357)

Provision for credit losses 1,653 — 1,653

Transaction and other costs 840 — 840

Fleet start-up and lay-down costs — 2,082 (2,082)

Adjusted EBITDA $ 634,146 $ 921,593 $ (287,447)

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 .

EBITDA was $735.8 million for the year ended December 31, 2025 compared to $940.5 million for the year ended December 31, 2024.

Adjusted EBITDA was $634.1 million for the year ended December 31, 2025 compared to $921.6 million for the year ended December 31, 2024.

The decreases in EBITDA and Adjusted EBITDA primarily resulted from lower pricing and changes in activity levels in 2025 as described above under the captions Revenue , Cost of Services, and General and Administrative Expenses for the Year Ended December 31, 2025, Compared to Year Ended December 31, 2024 .

Liquidity and Capital Resources

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.

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.

Historically, our primary sources of liquidity consist of cash flows from operations, borrowings under our credit facilities, and finance leases for certain equipment.

While we believe that we can fund operations and current organic growth plans for our oilfield services business 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 intend to raise significant funds to support our current planned expansion of our power business which may include debt, project financing including non-recourse debt, and co-investments or equity.

Our primary uses of capital have been capital expenditures to support growth, both organic and through acquisitions, 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 increased by $7.6 million to $27.6 million as of December 31, 2025 compared to $20.0 million as of December 31, 2024, while working capital excluding cash and current liabilities under debt and lease arrangements decreased $5.5 million.

Effective July 24, 2025 (the “Agreement Date”), Liberty Energy Services LLC, Freedom Proppant LLC, Liberty Power Innovations LLC, LOS Leasing Company LLC, Liberty Advanced Equipment Technologies LLC and Proppant Express Solutions, LLC, as borrowers (the “Borrowers”), and the Company, as parent guarantor, entered into a new Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, sole book runner and joint lead arranger, and certain other lenders party thereto (the “Credit Agreement”), which provides for, among other things, a revolving credit facility with initial revolving commitments of $750.0 million, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable, inventory, and certain power generation assets.

As of December 31, 2025, the Company was party to the Credit Agreement (as defined herein), which provides for a revolving line of credit up to $750.0 million (the “Revolving Credit Facility”).

The Credit Agreement is subject to certain borrowing base limitations based on a percentage of eligible accounts receivable, inventory, and certain power generation assets available to finance working capital needs.

As of December 31, 2025, the borrowing base was calculated to be $503.0 million, and the Company had $230.0 million outstanding, in addition to letters of credit totaling $19.2 million, with $253.8 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.

The Company is seeking an amendment (the “Amendment”) to the Credit Agreement that, among other things, would (i) permit the incurrence of new bridge loan indebtedness in an aggregate principal amount not to exceed $600.0 million (“Permitted Bridge Indebtedness”), which must be incurred on or prior to June 30, 2026 and have a scheduled maturity date not later than 365 days from the date of incurrence, (ii) subject to certain limitations and requirements, permit liens securing the Permitted Bridge Indebtedness, (iii) increase the basket for permitted convertible indebtedness from $300.0 million to $600.0 million, and (iv) amend the maturity date of the Revolving Credit Facility to provide that such maturity date will be accelerated to the date that is 91 days prior to the stated maturity of any outstanding Permitted Bridge Indebtedness if such Permitted Bridge Indebtedness is still outstanding on such date.

The Credit Agreement contains financial covenants that we are required to maintain, in addition to covenants that restrict our ability to take certain actions.

As of December 31, 2025, we are in compliance with all debt covenants.

On December 9, 2025, LOS Leasing Company LLC, as borrower, Liberty Energy Services LLC, as guarantor and permitted user, and LPI, as permitted user, entered into a Master Loan and Security Agreement with Caterpillar Financial Services Corporation (“Caterpillar” and such agreement, the “Caterpillar Agreement”).

The Caterpillar Agreement provides for term loans to finance costs incurred by LOS Leasing Company LLC in connection with the refurbishment of Caterpillar-manufactured equipment from authorized dealers of Caterpillar equipment.

Under the Caterpillar Agreement, LOS Leasing Company LLC and Caterpillar can enter into individual loan schedules (“Note”), which are non-revolving and may not be repaid and reborrowed.

Each Note is collateralized by specified units of the Company’s field services equipment, as documented in the applicable Note, will have a maturity date that is typically three years from the inception of the applicable Note, and interest rate that resets periodically based on the applicable base rate plus a spread.

As of December 31, 2025 the Company had $16.7 million outstanding under the Caterpillar Agreement with a maturity date of January 01, 2029 and interest rate of 6.6%.

As of December 31, 2024, the Company was party to the ABL Facility.

Effective July 24, 2025, (i) the outstanding debt under the ABL Facility was repaid in full, (ii) the outstanding liabilities with respect to obligations under the ABL Facility were released and discharged, (iii) all liens, security interests and guaranties under the ABL Facility were released and terminated and (iv) all letters of credit issued and outstanding under the ABL Facility were continues as letters of credit issued and outstanding under the Revolving Credit Facility.

See Note 8 —Debt to the consolidated financial statements included in Part II, Item 8 of this Annual Report for further details.

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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.

The Company expects to fund any repurchases by using cash on hand, borrowings under the 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, 2025, the Company repurchased and retired shares of Class A Common Stock for $24.0 million, under the share repurchase program.

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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.

Net cash provided by operating activities was $609.6 million for the year ended December 31, 2025, compared to $829.4 million for the year ended December 31, 2024.

The $219.8 million decrease in cash from operating activities is primarily attributable to a $309.0 million decrease in revenues, offset by a $77.5 million decrease in cash operating expenses, interest expense, net, and income tax expense, and a $2.4 million increase in cash from changes in working capital for the year ended December 31, 2025, compared to a $9.4 million decrease in cash from changes in working capital for the year ended December 31, 2024.

Investing Activities .

Net cash used in investing activities was $435.0 million for the year ended December 31, 2025, compared to $643.1 million for the year ended December 31, 2024.

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.

Cash used in investing activities was lower during the year ended December 31, 2025, compared to the year ended December 31, 2024 primarily due to a $134.3 million decrease in new equipment purchases and capitalized maintenance of existing equipment, as well as proceeds of $151.0 million from the sale of shares of Oklo, offset by a $78.8 million increase in deposits on new equipment orders.

During the year ended December 31, 2025, the Company acquired IMG Energy Solutions for total cash consideration of approximately $15.2 million, net of cash received, after closing adjustments.

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 IMG Acquisition.

Financing Activities .

Net cash used in financing activities was $167.5 million for the year ended December 31, 2025, compared to $202.7 million for the year ended December 31, 2024.

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.

The $35.2 million decrease in cash used in financing activities was primarily due to a $104.4 million decrease in share repurchases year over year, $16.7 million in proceeds under the Caterpillar Agreement compared to none in the prior year and a $3.1 million decrease in tax withholding on restricted stock units.

These decreases were offset by a $35.6 million increase in payments pursuant to the TRAs, a $30.6 million increase in cash paid for finance leases, a $11.0 million decrease in net borrowings on the Revolving Credit Facility, a $6.2 million increase in dividends paid, and a $5.7 million increase in debt issuance costs.

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.

Our material cash commitments consist primarily of obligations under long-term debt on the Revolving Credit 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 and our expansion into the distributed power business.

Certain amounts included in our contractual obligations as of December 31, 2025 are based on our estimates and assumptions about these obligations, including pricing, volumes, and duration.

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Included in those liabilities, the Company had expected cash payments for estimated interest on our finance lease obligations of $17.9 million payable within the next twelve months and $19.9 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, 2025, the Company has purchase obligations of $11.6 million payable within the next twelve months.

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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.

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.

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In the year ended December 31, 2025, the Company’s U.S.

net deferred tax liabilities were $137.7 million and Canada net deferred tax assets were $1.5 million.

net deferred tax liabilities were $195.6 million and Canada and Australia net deferred tax assets were $2.8 million and $1.9 million, respectively.

The Company has no valuation allowances recorded against the deferred tax assets for the year ended December 31, 2025 and 2024.

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Revenue Recognition:

Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements.

Revenue from our 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.

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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 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

of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment.

Inventory consists of raw materials used in the completions 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 of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment.

Property and Equipment:

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however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception.

Equity Investments:

The Company may from time to time invest in equity securities of public and private companies.

Equity investments are measured and recorded as follows:

Marketable equity investments are equity investments with a readily determinable fair value and are recorded at fair value on a recurring basis with changes in fair value, whether realized or unrealized, recorded through the income statement.

Unrealized gains and losses resulting from changes in fair value are recorded in gain on investments, net.

Equity securities without readily determinable fair values are measured at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer The Company monitors its equity investments without readily determinable fair values to identify potential transactions that may indicate an observable price change in orderly transactions for the identical or a similar investment of the same issuer, requiring adjustment to its carrying amount.

Gains and losses resulting from changes in observable prices are recorded in gain on investments, net.

Equity method investments are equity securities in investees we do not control, but over which we have the ability to exercise significant influence.

Equity method investments are measured at cost minus impairment, if any, plus or minus the Company’s share of equity method investee income or loss, less distributions received as return on investment.

Tax Receivable Agreements:

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis