Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following Management’s Discussion and Analysis of Financial Condition and Results of Operation (“MD&A”) is intended to help the reader understand the results of operations and financial condition of Texas Pacific Land Corporation. MD&A is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the accompanying notes to financial statements included in Part II, Item 8. of this Annual Report on Form 10-K. This discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including, but not limited to, those factors presented in Part I, Item 1A. “Risk Factors” and elsewhere in this Annual Report on Form 10-K. This section generally discusses the results of our operations for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion of the year ended December 31, 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” in our Annual Report on Form 10-K for the year ended December 31, 2024.
Overview
TPL was originally organized in 1888 as a business trust to hold title to extensive tracts of land in the State of Texas that were previously the property of the Texas and Pacific Railway Company. On January 11, 2021, we completed our Corporate Reorganization from a business trust to a corporation and changed our name from Texas Pacific Land Trust to Texas Pacific Land Corporation.
Our business activity is generated from our surface and royalty interest ownership, primarily in the Permian Basin. Our revenues are derived from oil and gas royalties, water sales, produced water royalties, easements and other surface-related income and land sales. Due to the nature of our operations and concentration of our ownership in one geographic location, our revenue and net income are subject to substantial fluctuations from quarter to quarter and year to year. In addition to fluctuations in response to changes in the market price for oil and gas, our financial results are subject to decisions by not only the owners and operators of oil and gas wells to which our oil and gas royalty interests relate, but also to other owners and operators in the Permian Basin as it relates to our other revenue streams, principally water sales, produced water royalties, easements and other surface-related revenue.
Market Conditions
Average West Texas Intermediate (“WTI”) oil prices for the year ended December 31, 2025 were down approximately 15% compared to average WTI oil prices during the same period last year. Oil prices continue to be impacted by certain actions by OPEC+, geopolitics, and evolving global supply and demand trends, among other factors. In addition, ambiguity around tariffs implemented by and towards the United States has created incremental global economic uncertainty, which, in part, contributed to relatively weaker oil prices in 2025. Average Henry Hub natural gas prices during 2025 increased approximately 61% compared to average prior year natural gas prices. Global and domestic natural gas markets benefited in 2025 from improved supply-demand balances, including tailwinds from expanded liquefied natural gas capacity and improved industrial and power demand, among other factors. Since mid-2022, the Waha Hub located in Pecos County, Texas has at times experienced significant negative price differentials relative to Henry Hub, located in Erath, Louisiana, due in part to growing local Permian natural gas production and limited natural gas pipeline takeaway capacity. Midstream infrastructure is currently being developed by operators to provide additional takeaway capacity, though the impact on future basis differentials will be dependent on future natural gas production and other factors. Changes in global and domestic macro-economic conditions could result in additional shifts in oil and gas supply and demand in future periods. Although our revenues are directly and indirectly impacted by oil and natural gas prices, we believe our royalty interests (which require no capital expenditures or operating expense from us for well development), balance sheet, and liquidity position will help us navigate through potential commodity price .
As the largest oil producing shale basin in the world, the Permian depends on large-scale water solutions related to well development and produced water disposal. For oil and gas well development, often hundreds of thousands of barrels of water are required per well completion. To enhance productivity and drilling economics, oil and gas operators have generally expanded the amount of water per well completion and reduced the time to complete a well. These factors have led to intensifying demands for completion water delivery and assurance, which generally benefits completion water providers with larger size and scale. We believe we have a competitive advantage in this market with our significant surface footprint and a large network of owned and operated water wells, storage ponds, recycling assets, and pipelines that can source and deliver water to customers throughout the Permian.
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Permian produced water volumes have grown commensurately with overall Permian oil production. Though some produced water is reused and recycled for completion activities, the majority of Permian produced water is injected into subsurface pore space via saltwater disposal wells. Saltwater disposal availability varies throughout the Permian depending on regulations, permitted injected rates, and the availability of pore space and infrastructure. Our extensive land holdings contain and are adjacent to extensive pore space, and, through various commercial agreements, we allow produced water operators to transport and dispose of produced water across our surface footprint. Furthermore, our previously mentioned desalination project could potentially provide an additional solution for produced water by reducing the amount of water required to be injected subsurface.
Permian Basin Activity
The Permian Basin is one of the oldest and most well-known hydrocarbon-producing areas and currently accounts for a substantial portion of oil and gas production in the United States, covering approximately 86,000 square miles in 52 counties across southeastern New Mexico and western Texas. Exploration and production (“E&P”) companies active in the Permian generally decreased their drilling and development activity in 2025 compared to recent prior year activity levels in response to lower oil prices. Despite relatively lower activity, Permian production, per the U.S. Energy Information Administration (“EIA”), averaged approximately 6.5 million barrels of oil per day during 2025.
Due to our ownership concentration in the Permian Basin, our revenues are directly impacted by oil and gas pricing and drilling activity in the Permian Basin. The metrics below show selected benchmark oil and natural gas prices and approximate activity levels in the Permian Basin for the years ended December 31, 2025 and 2024:
Years Ended December 31,
Oil and Gas Pricing Metrics: (1)
WTI Cushing average price per Bbl
Henry Hub average price per mmbtu
Waha Hub natural gas average price per mmbtu
Activity Metrics specific to the Permian Basin: (1)(2)
Average monthly horizontal permits
Average monthly horizontal wells drilled
Average weekly horizontal rig count
DUCs as of December 31 for each applicable year
Total Average U.S. weekly horizontal rig count (2)
(1) Commonly used definitions in the oil and gas industry: “WTI Cushing” represents West Texas Intermediate. “Bbl” represents one barrel of 42 U.S. gallons of crude oil, condensate or NGLs. “Mmbtu” represents one million British thermal units, a measurement used for natural gas. “DUCs” represent drilled but uncompleted wells. DUC classification is based on well data and date stamps provided by Enverus. DUCs is based on wells that have a drilled/spud date stamp but do not have a completed or first production date stamp. Excludes wells that have been labeled plugged and abandoned or permit expired and wells drilled/spud more than five years ago.
(2) Permian Basin specific information per Enverus analytics. U.S. weekly horizontal rig counts per Baker Hughes United States Rotary Rig Count for horizontal rigs. Statistics for similar data are also available from other sources. The comparability between these other sources and the sources used by the Company may differ.
While average oil prices for the year ended December 31, 2025 were lower compared to the same period in 2024, Henry Hub and Waha Hub natural gas prices for the year ended December 31, 2025 increased compared to the same period last year. E&P companies broadly have continued to deploy capital towards drilling and development activities in the Permian Basin at a measured pace. Although average rig counts during the year ended December 31, 2025 were lower compared to the same period last year, increased drilling and completion efficiencies have allowed operators, in aggregate, to grow production. As we are a significant landowner in the Permian Basin and not an oil and gas producer, our revenue is affected by the development decisions made by companies that operate in the areas where we own royalty interests and land. Accordingly, these decisions made by others affect, both directly and indirectly, our oil and gas royalties, produced water royalties, water sales, and other surface-related income.
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Liquidity and Capital Resources
Overview
Our principal sources of liquidity are cash and cash flows generated from operations and our Credit Facility. Our primary liquidity and capital requirements are for acquisitions, capital expenditures related to our Water Services and Operations segment (the extent and timing of which are under our control), working capital, and general corporate needs.
We continuously review our levels of liquidity and capital resources. If market conditions were to change and our revenues were to decline significantly or operating costs were to increase significantly, our cash flows and liquidity could be reduced. Should this occur, we could draw on our Credit Facility or seek alternative sources of funding. As of December 31, 2025, we had no debt, draws on our Credit Facility, and no off-balance sheet arrangements that require us to provide funding, guarantees, or other forms of financial support.
As we evaluate our current capital structure, capital allocation priorities, business fundamentals, and investment opportunities, we have set a target cash and cash equivalents balance of approximately $700 million. Above this target, we will seek to deploy the majority of our free cash flow towards returning capital to our stockholders in the form of special dividends and/or share repurchases. As of December 31, 2025, we had cash and cash equivalents of $144.8 million that we expect to utilize, along with cash flow from operations, to provide capital to support our business, to pay regular dividends, subject to the discretion of our Board, to, subject to market conditions, repurchase shares of our Common Stock, for potential acquisitions and for general corporate purposes. We believe that cash from operations and our cash and cash equivalents balance together with our Credit Facility, will be sufficient to meet ongoing capital expenditures, working capital requirements and other cash needs and allow for opportunistic transactions for at least the next 12 months.
Acquisition and Investment Activity
We completed the following asset acquisitions and investment during 2025:
• In March 2025, we acquired 177 NRA located primarily in the Midland Basin for an aggregate purchase price of $3.5 million, net of post-closing adjustments, in an all-cash transaction.
• In May 2025, we acquired 787 acres of land in Reeves County, Texas for an aggregate purchase price, inclusive of closing costs, of $4.5 million in an all-cash transaction.
• In September 2025, we acquired 8,147 acres of land in Martin, County Texas for an aggregate purchase price, inclusive of closing costs, of $31.4 million in an all-cash transaction.
• In November 2025, we acquired 17,306 NRA located primarily in the Midland Basin in Martin, Howard, Midland, and other counties for an aggregate purchase price of $450.7 million, net of post-closing adjustments, in an all-cash transaction.
• In December 2025, we made a minority investment of $50.0 million in Bolt pursuant to a strategic agreement to develop and enable large scale data center campuses and supporting infrastructure across our land.
See Part I, Item 1. “Business — Recent Developments” for further discussion of our acquisition and investment activity during 2025.
Revolving Credit Facility
On October 23, 2025, we entered into a Credit Facility in the aggregate principal amount of up to $500.0 million, and the ability to request potential increases in the commitments of the lenders of up to an additional $250.0 million; provided that any such request for an increase must be in a minimum amount of $50.0 million or, if less, the amount remaining available for all such increases. The Credit Facility and all borrowings thereunder will mature on October 23, 2029.
The borrowings under the Credit Facility will bear interest at a rate per annum (i) for each SOFR loan, equal to term SOFR for such interest period plus (x) 2.25% if our consolidated total leverage ratio is less than or equal to 2.0 to 1.0 or (y) 2.50% if our consolidated total leverage ratio is greater than 2.0 to 1.0 or (ii) for each base rate loan, equal to the base rate plus (x) 1.25% if our consolidated total leverage ratio is less than or equal to 2.0 to 1.0 or (y) 1.50% if our consolidated total
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leverage ratio is greater than 2.0 to 1.0. The base rate for any day is a fluctuating rate per annum equal to the highest of (a) the federal funds rate plus 0.50% of 1%, (b) the rate of interest per annum publicly announced by the Administrative Agent as its prime rate, and (c) term SOFR for a one-month tenor in effect on such day plus 1.00%. We are also required to pay customary letter of credit fees.
We intend to draw on the facility primarily for capital expenditures, ongoing working capital, acquisitions and general corporate purposes. Borrowings under the Credit Facility will be unsecured with a springing security interest in substantially all equity securities of our subsidiaries in the event our consolidated total leverage ratio exceeds 2.50 to 1.0. The Credit Facility also contains customary financial and other affirmative and negative covenants.
The events of default under the Credit Facility include, among others, payment defaults, breaches of covenants, defaults under the related loan documents, material misrepresentations, cross defaults with certain other material indebtedness, bankruptcy and insolvency events, judgment defaults, certain events related to plans subject to the Employee Retirement Income Security Act of 1974, as amended, invalidity of the Credit Facility or the related loan documents and change in control events. The occurrence of an event of default could result in the termination of commitments and letter of credit extensions, the acceleration of our obligations under the Credit Facility, the requirement to post cash collateral with respect to letters of credit and the exercise of the Lenders of all rights and remedies under the Credit Facility.
No draws had been made under the Credit Facility as of December 31, 2025, and the Credit Facility remained undrawn as of the date of this Annual Report.
Return of Capital to Stockholders
During the year ended December 31, 2025, we paid total dividends to our stockholders of $147.8 million, consisting of cumulative regular cash dividends of $2.13 per share. In addition, we repurchased $8.4 million of our Common Stock during the year ended December 31, 2025.
Development of New Solutions for Produced Water and Capital Expenditures
In 2024, we announced our progress towards developing a patented energy-efficient desalination and treatment process and associated equipment that can recycle produced water into fresh water with quality standards appropriate for surface discharge and beneficial reuse. With the Permian Basin generating over 20 million barrels of produced water per day, this technology provides an attractive and critical alternative to subsurface injection. We have begun construction of our test facility, which will have an initial capacity of 10,000 barrels of water per day, with an estimated service date in the first half of 2026. Cumulatively through December 31, 2025, we have spent $45.5 million ($33.6 million during the year ended December 31, 2025) on this new energy-efficient desalination and treatment process and equipment, of which $38.8 million had been capitalized as of December 31, 2025.
Additionally, during the year ended December 31, 2025, we invested approximately $24.9 million to enhance our water sourcing assets.
Cash Flows from Operating Activities
For the years ended December 31, 2025 and 2024, net cash provided by operating activities was $545.9 million and $490.7 million, respectively. Our cash flow provided by operating activities is primarily from oil, gas and produced water royalties, water and land sales, easements, and other surface-related income. Cash flow used in operations generally consists of operating expenses associated with our revenue streams, general and administrative expenses and income taxes.
The increase in cash flows provided by operating activities for the year ended December 31, 2025 compared to the same period of 2024 was primarily driven by an increase in operating income, principally related to increased oil and gas production volumes and water sales volumes, and changes in working capital requirements during 2025 as compared to 2024.
Cash Flows Used in Investing Activities
For the years ended December 31, 2025 and 2024, net cash used in investing activities was $595.8 million and $471.7 million, respectively. Our cash flows used in investing activities are primarily related to royalty acquisitions, investments and purchases of fixed assets primarily related to our Water Services and Operations segment. Our acquisitions may include royalty interests, land and other similar tangible and intangible assets.
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For further information regarding acquisitions and investment activity during the year ended December 31, 2025, see “Acquisition and Investment Activity” above. Purchases of fixed assets for the years ended December 31, 2025 and 2024 were $59.5 million and $29.7 million, respectively.
Cash Flows Used in Financing Activities
For the years ended December 31, 2025 and 2024, net cash used in financing activities was $176.0 million and $378.1 million, respectively. Our cash flows used in financing activities principally consist of activities that return capital to our stockholders such as payments of dividends and repurchases of our Common Stock, and activity related to our Credit Facility.
During the year ended December 31, 2025, we paid total dividends of $147.8 million, consisting of cumulative regular cash dividends of $2.13 per share. During the year ended December 31, 2024, we paid total dividends of $347.3 million consisting of cumulative regular cash dividends of $1.70 per share and a special dividend of $3.33 per share. During the years ended December 31, 2025 and 2024, employees surrendered $14.8 million and $1.6 million in shares, respectively, to the Company to settle tax withholdings related to stock vesting. We repurchased $8.4 million and $29.2 million of our Common Stock during the years ended December 31, 2025 and 2024, respectively. Debt issuance cost in connection with the Credit Facility was $5.1 million for the year ended December 31, 2025. We had no draws or repayments on the Credit Facility during the year ended December 31, 2025.
Results of Operations
The following table shows our consolidated results of operations and our results of operations by reportable segment for Land and Resource Management (“LRM”) and Water Service and Operations (“WSO”) for the years ended December 31, 2025 and 2024 (in thousands):
Years Ended December 31,
LRM
WSO
Consolidated
LRM
WSO
Consolidated
Revenues:
Oil and gas royalties
Water sales
Produced water royalties
Easements and other surface-related income
Land sales
Total revenues
Expenses:
Salaries and related employee expenses
Water service-related expenses
General and administrative expenses
Depreciation, depletion and amortization
Ad valorem and other taxes
Total operating expenses
Operating income
Interest expense
Other income, net
Income before income taxes
Income tax expense
Net income
Interest income by segment is included in other income, net in the table above.
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Consolidated Results of Operations
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Total revenues were $798.2 million for the year ended December 31, 2025 compared to $705.8 million for the year ended December 31, 2024. Total operating expenses were $206.0 million for the year ended December 31, 2025 compared to $166.7 million for the year ended December 31, 2024. Net income was $481.4 million for the year ended December 31, 2025 compared to $454.0 million for the year ended December 31, 2024. Individual revenue and expense line items are discussed below under “Segment Results of Operations.”
Segment Results of Operations
We operate our business in two reportable segments: Land and Resource Management and Water Services and Operations. We eliminate any inter-segment revenues and expenses, if any, upon consolidation.
We evaluate the performance of our operating segments separately to monitor the different factors affecting financial results. The reportable segments presented are consistent with our reportable segments discussed in Note 16, “Business Segment Reporting” in the notes to our consolidated financial statements included under Part II, Item 8. “Financial Statements and Supplementary Data.” We monitor our reporting segments based upon revenue and net income calculated in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
Our oil and gas royalty revenue, and, in turn, our results of operations for the year ended December 31, 2025 have been impacted by lower average commodity prices compared to 2024. However, our oil and gas royalty revenues increased for the year ended December 31, 2025 due to increased royalty production. Additionally, revenues derived from water sales and produced water royalties for the year ended December 31, 2025 were also positively impacted by our active management of our surface and royalty interests in recent years.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Land and Resource Management
Oil and gas royalties . Oil and gas royalty revenue was $411.7 million for the year ended December 31, 2025 compared to $373.3 million for the year ended December 31, 2024, an increase of 10.3%. Our share of production volumes increased to 34.6 thousand Boe per day for the year ended December 31, 2025 compared to 26.8 thousand Boe per day for 2024. The average realized prices decreased to $34.18 per Boe for the year ended December 31, 2025 from $39.87 per Boe for 2024, a decrease of 14.3%.
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The table below provides financial and operational data by oil and gas royalty stream for the years ended December 31, 2025 and 2024:
Years Ended December 31,
Our share of production volumes (1) :
Oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)
Equivalents (MBoe)
Equivalents per day (MBoe/d)
Oil and gas royalties (in thousands):
Oil royalties
Natural gas royalties
NGL royalties
Total oil and gas royalties
Realized prices:
Oil ($/Bbl)
Natural gas ($/Mcf)
NGL ($/Bbl)
Equivalents ($/Boe)
(1) Commonly used definitions in the oil and gas industry: “Bbl” represents one barrel of 42 U.S. gallons of crude oil, condensate or NGLs. “Boe” represents barrels of oil equivalent. “NGL” represents natural gas liquid. “MBbls” represents one thousand barrels of crude oil, condensate or NGLs. “Mcf” represents one thousand cubic feet of natural gas. “MMcf” represents one million cubic feet of natural gas. “MBoe” represents one thousand Boe. “MBoe/d” represents one thousand Boe per day.
Easements and other surface-related income. Easements and other surface-related income was $78.2 million for the year ended December 31, 2025, an increase of 24.0% compared to $63.1 million for the year ended December 31, 2024. Easements and other surface-related income includes revenue related to the use and crossing of our land for oil and gas exploration and production, renewable energy, and agricultural operations. The increase in easements and other surface-related income was principally related to increases of $10.0 million in pipeline easements, $3.8 million in wellbore easements and $2.5 million in lease bonuses on acquired royalty interests for the year ended December 31, 2025 compared to the same period of 2024. The amount of income derived from pipeline easements is a function of the term of the easement, the size of the easement, and the number of easements entered into for any given period. Easements and other surface-related income is dependent on development decisions made by companies that operate in the areas where we own land and is, therefore, unpredictable and may vary significantly from period to period. See “Permian Basin Activity” above for additional discussion of development activity in the Permian Basin during the year ended December 31, 2025.
Land sales . Land sales were $0.8 million and $4.4 million for the years ended December 31, 2025 and 2024, respectively. For the year ended December 31, 2025, we sold 17 acres of land for an aggregate sales price of $0.8 million. For the year ended December 31, 2024, we sold 439 acres of land for an aggregate sales price of approximately $4.4 million.
Salaries and related employee expenses. Salaries and related employee expenses, which include not only salaries, equity and non-equity incentive compensation, but also employee benefits and contract labor expense, were $29.2 million for the year ended December 31, 2025 compared to $27.5 million for the same period of 2024. The increase in salaries and related employee expenses was principally related to market compensation adjustments that take effect annually at the start of a given year.
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General and administrative expenses. General and administrative expenses were $14.4 million for the year ended December 31, 2025 compared to $25.5 million for the same period of 2024. The decrease was primarily due to a decrease in legal and professional fees of $11.9 million over the same period of 2024.
Depreciation, depletion and amortization. Depreciation, depletion and amortization was $44.6 million for the year ended December 31, 2025 compared to $11.0 million for the same period of 2024. The increase was principally due to depletion expense associated with royalty interests acquired during the second half of both 2025 and 2024.
Other income, net. Other income, net was $14.9 million for the year ended December 31, 2025 compared to $31.7 million for the same period of 2024. Lower cash balances and investment yields during the year ended December 31, 2025 compared to the same period of 2024 resulted in a decrease in interest income. During the year ended December 31, 2024, we recorded a curtailment and settlement gain of $3.3 million related to our pension plan. Additionally, during the year ended December 31, 2024, we received $1.9 million of proceeds from a settlement with a title company regarding a defect in title to a property acquired in a previous year.
Water Services and Operations
Water sales . Water sales revenue increased $19.0 million to $169.7 million for the year ended December 31, 2025 compared to $150.7 million for the year ended December 31, 2024. The growth in water sales was principally due to increases of 8.8% in water sales pricing and 3.4% in volumes for the year ended December 31, 2025 compared to the year ended December 31, 2024.
Produced water royalties. Produced water royalties are royalties received from the transfer or disposal of produced water on our land. Produced water royalties are contractual and not paid as a matter of right. We do not operate any saltwater disposal wells. Produced water royalties were $124.2 million for the year ended December 31, 2025 compared to $104.1 million in 2024. This increase was principally due to a 24.6% increase in produced water volumes for the year ended December 31, 2025 compared to 2024.
The table below provides financial and operational data by water revenue type for the years ended December 31, 2025 and 2024:
Years Ended December 31,
Water volumes (in MBbls) (1) :
Water sales
Produced water royalties
Water volumes in barrels per day (in MBbls/d) (2) :
Water sales
Produced water royalties
Water revenue (in thousands):
Water sales
Produced water royalties
(1) MBbl = 1 thousand barrels of water.
(2) MBbl/d = 1 thousand barrels of water per day.
Easements and other surface-related income . Easements and other surface-related income was $13.5 million for the year ended December 31, 2025, an increase of $3.4 million compared to $10.2 million for the year ended December 31, 2024. The increase in easements and other surface-related income primarily related to an increase in temporary permits for sourced water lines for the year ended December 31, 2025 compared to 2024.
Salaries and related employee expenses. Salaries and related employee expenses, which include not only salaries, equity and non-equity incentive compensation, but also employee benefits and contract labor expense, were $28.7 million for the year ended December 31, 2025 compared to $26.1 million for the same period of 2024. The increase in salaries and related
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employee expenses is principally related to increased contract labor costs associated with development of an in-house water management application and market compensation adjustments that take effect annually at the start of the year.
Water service-related expenses. Water service-related expenses increased $7.4 million to $53.5 million for the year ended December 31, 2025 compared to 2024. Certain types of water service-related expenses, including, but not limited to, treatment, transfer, water purchases, repairs and maintenance, equipment rental, and fuel costs vary from period to period as our customers’ needs and requirements change. Right of way and other expenses also vary from period to period depending on the location of customer delivery. The increase in water service-related expenses for the year ended December 31, 2025 was principally related to increased water sales volumes compared to the same period of 2024. Research and development expenses related to development of a new energy-efficient method of produced water desalination and treatment were $2.8 million and $2.5 million for the years ended December 31, 2025 and 2024, respectively. For further discussion of this new treatment method, see “Liquidity and Capital Resources — Development of New Solutions for Produced Water and Capital Expenditures” above.
Depreciation, depletion and amortization. Depreciation, depletion and amortization was $18.0 million for the year ended December 31, 2025 compared to $14.2 million for the comparable period of 2024. The increase was principally due to depreciation expense related to new water service-related assets placed in service.
Other income, net. Other income, net was $3.9 million for the year ended December 31, 2025 compared to $8.0 million for the same period of 2024. Lower cash balances and investment yields during the year ended December 31, 2025 compared to the same period of 2024 resulted in a decrease in interest income. Additionally, during the year ended December 31, 2024, we recorded a curtailment and settlement gain of $1.3 million related to our pension plan.
Income tax expense. Income tax expense was $42.6 million for the year ended December 31, 2025 compared to $38.5 million for the same period of 2024. The increase in income tax expense was directly attributable to the increase in operating income for the year ended December 31, 2025 compared to the same period of 2024.
Non-GAAP Performance Measures
In addition to amounts presented in accordance with GAAP, we also present certain supplemental non-GAAP performance measurements. These measurements are not to be considered more relevant or accurate than the measurements presented in accordance with GAAP. In compliance with the requirements of the SEC, our non-GAAP measurements are reconciled to net income, the most directly comparable GAAP performance measure. For all non-GAAP measurements, neither the SEC nor any other regulatory body has passed judgment on these non-GAAP measurements.
EBITDA, Adjusted EBITDA and Free Cash Flow
EBITDA is a non-GAAP financial measurement of earnings before interest expense, taxes, depreciation, depletion and amortization. The purpose of presenting EBITDA is to highlight earnings without finance, taxes, and depreciation, depletion and amortization expense, and its use is limited to specialized analysis.
The purpose of presenting Adjusted EBITDA is to highlight earnings without non-cash activity such as share-based compensation and other non-recurring or unusual items, if applicable. Additionally, Adjusted EBITDA is a metric used by the Compensation Committee to evaluate our performance in determining the short-term and long-term incentive compensation of our executive officers on an annual basis. We calculate Adjusted EBITDA as EBITDA plus employee share-based compensation less pension curtailment and settlement gain. The pension curtailment and settlement gain are related to a buyout by a third party of defined benefit obligations under our pension plan and the subsequent freezing of our pension plan, both of which occurred in the fourth quarter of 2024. We have excluded the pension curtailment and settlement gain from the calculation of Adjusted EBITDA as such gain is a non-recurring item and is not related to our core business.
The purpose of presenting free cash flow is to provide investors a metric to measure the funds available for investing in future acquisitions and returning capital to our stockholders through dividends and share repurchases after current income tax expense and purchases of fixed assets. Additionally, free cash flow is a metric used by the Compensation Committee to evaluate our performance in determining the short-term and long-term incentive compensation of our executive officers. To calculate free cash flow, net income is adjusted by adding back income tax expense, depreciation, depletion and amortization and employee share-based compensation, less the cash outflows of current income tax expenses, purchases of fixed assets and pension curtailment and settlement gain.
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We have presented EBITDA, Adjusted EBITDA and free cash flow because we believe that these metrics are useful supplements to net income in analyzing our operating performance, ability to fund future acquisitions, ability to return capital to our stockholders and explaining how our Named Executive Officers (as defined below) are compensated. Our definitions of EBITDA, Adjusted EBITDA and free cash flow may differ from computations of similarly titled measures of other companies.
The following table presents a reconciliation of net income to EBITDA and Adjusted EBITDA for the years ended December 31, 2025 and 2024 (in thousands):
Years Ended December 31,
Net income
Add:
Interest expense
Income tax expense
Depreciation, depletion and amortization
EBITDA
Add (deduct):
Employee share-based compensation
Pension curtailment and settlement gain
Adjusted EBITDA
The following table presents a reconciliation of net income to free cash flow for the years ended December 31, 2025 and 2024 (in thousands):
Years Ended December 31,
Net income
Add (deduct):
Income tax expense
Depreciation, depletion and amortization
Employee share-based compensation
Pension curtailment and settlement gain
Current income tax expense
Purchase of fixed assets
(Increase) decrease in accounts payable related to purchases of fixed assets
Free cash flow
Off-Balance Sheet Arrangements
We have not entered into off-balance sheet arrangements that require us to provide funding, guarantees or any other form of financial support.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements. It is our opinion that we fully disclose our significant accounting policies in the notes to the consolidated financial statements. Consistent with our disclosure policies, we include the following discussion related to what we believe to be our most critical accounting policies that require our most difficult, subjective or complex judgment and estimates.
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Accrual of Oil and Gas Royalties
We accrue oil and gas royalties. An accrual is necessary due to the time lag between the removal of crude oil and gas products from the respective mineral reserve locations and generation of the actual payment by operators. The oil and gas royalty accrual is based upon historical production volumes, estimates of the timing of future payments and recent market prices for oil and gas.
Oil and Gas Reserves
We account for our acquired oil and gas royalty interests using the successful-efforts method. Under this method, costs to acquire oil and gas royalty interests are capitalized. Acquisition costs associated with non-producing oil and gas royalty interests are recorded as unproved properties until the results of leasing and drilling activities performed by third-party exploration and production operators provide sufficient information to determine whether such interests contain proved reserves. When unproved properties are determined to have proved developed producing reserves (“PDP”), the related capitalized costs are transferred to proved oil and gas properties. The Company only reports PDP reserves as we do not control the timing or development of drilling activities.
The estimation of PDP oil and gas reserves involves significant judgment by independent petroleum engineers. Reserve estimates rely on geological and engineering analysis, production data, the development and operating plans of third-party operators on our acreage, and assumptions regarding commodity prices and economic conditions. Because we calculate depletion of proved oil and gas royalty interests on a unit-of-production basis, changes in reserve estimates influence the rate at which capitalized costs are depleted and the timing of transfers from unproved to proved properties.
We group oil and gas royalty interests for depletion using a reasonable aggregation of properties with similar geological or stratigraphic characteristics. Reserve estimates are updated at least annually, or more frequently when new information becomes available. Revisions to these estimates whether due to operator development activity, production performance, technical analysis, or changes in economic assumptions result in prospective adjustments to depletion and may impact the pattern in which capitalized costs are recognized over time.
Recent Accounting Pronouncements
For further information regarding recently issued accounting pronouncements, see Note 2, “Summary of Significant Accounting Policies” in the notes to our consolidated financial statements included under Part II, Item 8. “Financial Statements and Supplementary Data.”
