# Liberty Energy Inc. (LBRT)

Informational only - not investment advice.

CIK: 0001694028
SIC: 1389 Oil & Gas Field Services, NEC
SIC breadcrumb: [Mining](/division/B/) > [SIC Major Group 13](/major-group/13/) > [SIC 1389 Oil & Gas Field Services, NEC](/industry/1389/)
Latest 10-K filed: 2026-02-02
SEC page: https://www.sec.gov/edgar/browse/?CIK=1694028
Filing source: https://www.sec.gov/Archives/edgar/data/1694028/000169402826000006/lbrt-20251231.htm

## Selected Fundamentals
| Metric | Value | Unit | FY | Filed |
| --- | ---: | --- | ---: | --- |
| Revenue | 4006116000 | USD | 2025 | 2026-02-02 |
| Net income | 147872000 | USD | 2025 | 2026-02-02 |
| Assets | 3558305000 | USD | 2025 | 2026-02-02 |

## Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-02. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001694028.json. Derived margins are computed from the extracted annual SEC facts.

| Metric | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Revenue | 374,773,000 | 1,489,855,000 | 2,155,136,000 | 1,990,346,000 | 965,787,000 | 2,470,782,000 | 4,149,228,000 | 4,747,928,000 | 4,315,161,000 | 4,006,116,000 |
| Net income | 0.00 | 0.00 | 126,349,000 | 39,003,000 | -115,583,000 | -179,244,000 | 399,602,000 | 556,317,000 | 316,010,000 | 147,872,000 |
| Operating income | -54,434,000 | 181,137,000 | 306,563,000 | 103,597,000 | -177,026,000 | -181,224,000 | 495,890,000 | 760,579,000 | 389,468,000 | 72,708,000 |
| Diluted EPS |  |  | 1.81 | 0.53 | -1.36 | -1.03 | 2.11 | 3.15 | 1.87 | 0.89 |
| Assets |  | 852,103,000 | 1,116,501,000 | 1,283,429,000 | 1,889,942,000 | 2,040,660,000 | 2,575,932,000 | 3,033,557,000 | 3,296,394,000 | 3,558,305,000 |
| Liabilities |  | 416,851,000 | 375,687,000 | 501,937,000 | 579,899,000 | 810,221,000 | 1,078,626,000 | 1,192,149,000 | 1,317,525,000 | 1,479,416,000 |
| Stockholders' equity | 228,972,000 | 392,766,000 | 740,814,000 | 781,492,000 | 1,310,043,000 | 1,230,439,000 | 1,497,306,000 | 1,841,408,000 | 1,978,869,000 | 2,078,889,000 |
| Cash and cash equivalents | 11,484,000 | 16,321,000 | 103,312,000 | 112,690,000 | 68,978,000 | 19,998,000 | 43,676,000 | 36,784,000 | 19,984,000 | 27,554,000 |
| Net margin | 0.00% | 0.00% | 5.86% | 1.96% | -11.97% | -7.25% | 9.63% | 11.72% | 7.32% | 3.69% |
| Operating margin | -14.52% | 12.16% | 14.22% | 5.20% | -18.33% | -7.33% | 11.95% | 16.02% | 9.03% | 1.81% |

## Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-23. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001694028.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

| Quarter | End date | Revenue | Net income | Diluted EPS | Method |
| --- | --- | ---: | ---: | ---: | --- |
| 2022-Q2 | 2022-06-30 |  |  | 0.55 | reported discrete quarter |
| 2022-Q3 | 2022-09-30 |  |  | 0.78 | reported discrete quarter |
| 2023-Q1 | 2023-03-31 |  |  | 0.90 | reported discrete quarter |
| 2023-Q2 | 2023-06-30 | 1,194,988,000 | 152,671,000 | 0.87 | reported discrete quarter |
| 2023-Q3 | 2023-09-30 | 1,215,905,000 | 148,608,000 | 0.85 | reported discrete quarter |
| 2023-Q4 | 2023-12-31 | 1,074,958,000 | 92,383,000 |  | derived Q4 = FY annual - nine-month YTD |
| 2024-Q1 | 2024-03-31 | 1,073,125,000 | 81,892,000 | 0.48 | reported discrete quarter |
| 2024-Q2 | 2024-06-30 | 1,159,884,000 | 108,421,000 | 0.64 | reported discrete quarter |
| 2024-Q3 | 2024-09-30 | 1,138,578,000 | 73,804,000 | 0.44 | reported discrete quarter |
| 2024-Q4 | 2024-12-31 | 943,574,000 | 51,893,000 |  | derived Q4 = FY annual - nine-month YTD |
| 2025-Q1 | 2025-03-31 | 977,461,000 | 20,111,000 | 0.12 | reported discrete quarter |
| 2025-Q2 | 2025-06-30 | 1,042,521,000 | 71,016,000 | 0.43 | reported discrete quarter |
| 2025-Q3 | 2025-09-30 | 947,397,000 | 43,055,000 | 0.26 | reported discrete quarter |
| 2025-Q4 | 2025-12-31 | 1,038,737,000 | 13,690,000 |  | derived Q4 = FY annual - nine-month YTD |
| 2026-Q1 | 2026-03-31 | 1,021,184,000 | 22,558,000 | 0.14 | reported discrete quarter |

## Macro Cross-References
- [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
- [UNRATE](/indicator/UNRATE/): Unemployment Rate
- [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate
- [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private
- [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit
- [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit
- [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
- [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
- [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
- [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
- [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
- [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
- [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food
- [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy
- [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter
- [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index
- [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
- [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities
- [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate
- [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
- [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm
- [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate
- [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio
- [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed
- [CE16OV](/indicator/CE16OV/): Employment Level
- [ICSA](/indicator/ICSA/): Initial Claims
- [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm
- [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm
- [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product
- [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period
- [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index
- [TCU](/indicator/TCU/): Capacity Utilization: Total Index
- [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units
- [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
- [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade
- [PCE](/indicator/PCE/): Personal Consumption Expenditures
- [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income
- [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate
- [M2SL](/indicator/M2SL/): M2
- [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance
- [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States
- [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States
- [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States
- [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States
- [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States
- [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized
- [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized
- [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks
- [GDP](/indicator/GDP/): Gross Domestic Product
- [GPDI](/indicator/GPDI/): Gross Private Domestic Investment
- [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment
- [PCEC](/indicator/PCEC/): Personal Consumption Expenditures
- [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services
- [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt
- [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product
- [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit
- [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts
- [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures
- [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing
- [USCONS](/indicator/USCONS/): All Employees, Construction
- [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade
- [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities
- [USGOVT](/indicator/USGOVT/): All Employees, Government
- [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private
- [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods
- [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
- [BUSINV](/indicator/BUSINV/): Total Business Inventories
- [EXPGS](/indicator/EXPGS/): Exports of Goods and Services
- [IMPGS](/indicator/IMPGS/): Imports of Goods and Services
- [IR](/indicator/IR/): Import Price Index (End Use): All Commodities
- [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand

## Latest quarter (10-Q)

Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/1694028/000169402826000023/lbrt-20260331.htm

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization.
Confidence: high
Filing date: 2026-04-23
Report date: 2026-03-31

Item 2. 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 the accompanying unaudited condensed consolidated financial statements and related notes. 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 “Cautionary Note Regarding Forward-Looking Statements,” the Annual Report under the heading “Item 1A. Risk Factors,” and in “Part II – Other Information, Item 1A. Risk Factors” included herein. We assume no obligation to update any of these forward-looking statements.

Overview

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 March 31, 2026. 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 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. 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 CO2e emission profile than the Tier IV DGB; (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 ForteSM solution, which uses a modular, standardized construction approach for generation sites to reduce the risk of project execution, (b) the TempoSM 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 ChorusSM solution to optimize power costs through the use of a mix of co-located generation and grid power.

24

Table of Contents

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

The conflict in Iran has driven attacks on regional energy infrastructure and the unprecedented effective closure of the Strait of Hormuz, inducing higher oil prices in the near term and raising the prospect of a sustained increase in supply side risk premiums. In parallel, global LNG markets may face multi-year constraints following recent attacks on Qatar’s Ras Laffan hub and other regional gas infrastructure. Over the course of 2026, this dynamic may support structural tailwinds for North America, as global consumers reevaluate energy supply chains and diversify sourcing, with greater reliance on U.S. and Canadian sourced oil and refined product supply.

Entering the year, frac markets were recalibrated for flattish activity expectations which should result in a tighter balance between the underlying supply of frac fleets to meet expected demand. Pricing pressure and softer activity over the past few years led to accelerated equipment cannibalization, fleet attrition, and underinvestment in next generation technology. The recent rise in oil prices is above early year expectations, and is expected to drive better E&P economics so long as such prices are sustained.

Related to power markets, U.S. power demand estimates continue to accelerate, exemplified by ERCOT’s recent projections that Texas grid demand could quadruple by 2032. This expansion may be met by a fundamental shift in the commercial landscape whereby hyperscalers are expected to increasingly rely on distributed power service providers to self-generate and bypass traditional grid constraints leading to greater demand for power generation capacity.

During the first quarter of 2026, the posted WTI price traded at an average of $72.74 per barrel (“Bbl”), as compared to the first quarter 2025 average of $71.78 per Bbl, and the fourth quarter of 2025 average of $59.62 per Bbl. In addition, during the first quarter of 2026, the Henry Hub price traded at an average of $4.71 per one million British thermal units (“MMBtu”), as compared to the first quarter of 2025 average of $4.14 per MMBtu, and the fourth quarter of 2025 average of $3.71 per MMBtu. Subsequent to March 31, 2026, the Henry Hub traded at an average of $2.83 per MMBtu and the WTI price traded at an average of $99.85 per Bbl through April 20, 2026. The average domestic onshore rig count for the United States and Canada was 741 rigs reported in the first quarter of 2026, down from the average in the first quarter 2025 of 788, and up from the fourth quarter of 2025 of 709, according to a report from Baker Hughes.

25

Table of Contents

Business Developments

Senior Convertible Notes Activity

In February 2026, we issued $770 million aggregate principal amount of 0% convertible senior notes due March 2031 (the “2031 Notes”), and in March 2026, we issued $525 million aggregate principal amount of 0% convertible senior notes due March 2032 (the “2032 Notes”). Net proceeds from the offerings of the 2031 Notes and the 2032 Notes were $746 million and $511.3 million, respectively, after deducting the initial purchasers’ discounts and commissions and offering expenses paid by us. Additionally, we entered into privately negotiated capped call transactions with respect to each of the 2031 Notes and the 2032 Notes with certain of the initial purchasers or their respective affiliates and certain other financial institutions at a cost of approximately $109.3 million and $77.2 million, respectively. For more information on the 2031 Notes and the 2032 Notes, see Note 7—Debt to the unaudited condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report.

Amendment to Credit Agreement

We are party to that certain credit agreement, dated July 24, 2025 (the “Credit Agreement”), which provides for, among other things, a revolving credit facility with initial revolving commitments of $750 million, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable, inventory and certain power generating assets (the “Revolving Credit Facility”). On February 3, 2026, we entered into the first amendment (the “Amendment”) to the Credit Agreement that, among other things, (i) permits the incurrence of new bridge loan indebtedness in an aggregate principal amount not to exceed $600 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, permits liens securing the Permitted Bridge Indebtedness, (iii) increases the basket for permitted convertible indebtedness from $300 million to $600 million, which basket is in addition to other baskets permitting the incurrence of such indebtedness, and (iv) amends 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. For more information on the Credit Agreement, see Note 7—Debt to the unaudited condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report.

26

Table of Contents

Results of Operations

[Excerpt truncated for page length; source filing is linked above.]

## Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization.
Confidence: high

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 2025 and 2024 items and year-to-year comparisons between 2025 and 2024. 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.

Overview

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 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. 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 CO2e emission profile than the Tier IV DGB; (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 ForteSM solution, which uses a modular, standardized construction approach for generation sites to reduce the risk of project execution, (b) the TempoSM power quality management system to manage high-amplitude, cyclical load variations associated with artificial intelligence workloads and (c)

37

when a grid interconnection is requested by the customer and available, the ChorusSM 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

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.

Acquisitions

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 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

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 23, 2026, horizontal rigs accounted for approximately 87% 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

38

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 2025.

Increased complexity and service intensity of horizontal well completions. In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced. As wellbores have increased in length, the number of frac stages and/or the number of perforation clusters (frac initiation points) has also increased. Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource. The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Liberty’s FracTrends database, from six million pounds per well in 2014 to roughly 25 million pounds per well in 2025. 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 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.

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.

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 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. 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 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.

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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.

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, 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.

40

Results of Operations

Year Ended December 31, 2025, Compared to Year Ended December 31, 2024

Years Ended December 31,

Description

2025

2024

Change

(in thousands)

Revenue

$

4,006,116 

$

4,315,161 

$

(309,045)

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 

Transaction and other costs

840 

— 

840 

Depreciation, depletion, and amortization

500,332 

505,050 

(4,718)

Loss (gain) on disposal of assets, net

16,691 

(5,337)

22,028 

Operating income

72,708 

389,468 

(316,760)

Other income, net

(122,483)

(13,803)

(108,680)

Net income before income taxes

195,191 

403,271 

(208,080)

Income tax expense

47,319 

87,261 

(39,942)

Net income

147,872 

316,010 

(168,138)

Revenue

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, 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 $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 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 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.

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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. Additionally, interest income—related party decreased $0.5 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 $47.3 million for the year ended December 31, 2025, an effective rate of 24.2%, compared to $87.3 million, for the year ended December 31, 2024, an effective rate of 21.6%. 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 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.

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.

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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, 2025, Compared to Year Ended December 31, 2024: EBITDA and Adjusted EBITDA

Years Ended December 31,

Description

2025

2024

Change

(in thousands)

Net income

$

147,872 

$

316,010 

$

(168,138)

Depreciation, depletion, and amortization

500,332 

505,050 

(4,718)

Interest expense, net

40,306 

32,214 

8,092 

Income tax expense

47,319 

87,261 

(39,942)

EBITDA

$

735,829 

$

940,535 

$

(204,706)

Stock-based compensation expense

41,922 

32,412 

9,510 

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 

Adjusted EBITDA

$

634,146 

$

921,593 

$

(287,447)

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

Overview

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. 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 or potential acquisitions that we pursue. 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 equivalents 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.

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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.

We have no material off balance sheet arrangements as of December 31, 2025, 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 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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Cash Flows

The following table summarizes our cash flows for the periods indicated:

Years Ended December 31,

Description

2025

2024

Change

(in thousands)

Net cash provided by operating activities

$

609,598 

$

829,374 

$

(219,776)

Net cash used in investing activities

(435,037)

(643,113)

208,076 

Net cash used in financing activities

(167,545)

(202,705)

35,160 

Analysis of Cash Flow Changes Between the Years Ended December 31, 2025 and December 31, 2024

Operating Activities. 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, 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 $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.

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Cash Requirements

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. We have no material off balance sheet arrangements as of December 31, 2025, 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, 2025, the Company expanded its equipment lease facilities resulting in the addition of $118.7 million in new finance lease obligations. The term on these new leases range from three to five years. As of December 31, 2025, the Company had finance lease obligations of $116.3 million payable within the next twelve months and $231.2 million payable thereafter. 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.

As of December 31, 2025, the Company has purchase obligations of $11.6 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, 2025, the Company expects to make a $7.9 million payment under the TRAs within the next twelve months. Future amounts payable under the TRAs are dependent upon future events. See Note 12—Income Taxes to 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, 2025.

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.

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

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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, 2025 was 24.2% compared to 21.6% for the year ended December 31, 2024. 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 $47.3 million and $87.3 million for the years ended December 31, 2025 and 2024, 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, 2025, the Company’s U.S. 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.

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 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. 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 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: 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.

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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.

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: 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.

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