TPL Texas Pacific Land Corp - 10-K

Item 1A. Risk Factors.

An investment in our securities involves a degree of risk. The risks described below, and other risks noted throughout this Annual Report, including those risks identified in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are not the only ones facing us. Additional risks not presently known to us or that we currently deem immaterial may also have a material adverse effect on us. If any of the following risks actually occur, our financial condition, results of operations, cash flows or business could be harmed. In that case, the market price of our stock could decline and you could lose part or all of your investment in our stock.

Risks Related to Our Business

Our oil and gas royalties are dependent upon the market prices of oil and gas which fluctuate.

The oil and gas royalties that we receive are dependent upon the market prices for oil and gas, and decreases in such prices for oil and gas negatively impact the revenue realized on our oil and gas royalties. Reductions in market prices for oil and gas could also lead to decreased exploration and development activity by the operators of the properties on which we own oil and gas royalty interests, which could reduce our revenue potential with respect to such interests. Market prices for oil and gas are subject to U.S. and global macroeconomic and geopolitical conditions and infrastructure and logistical constraints, amongst others, and, in the past, have been subject to significant price fluctuations. Price fluctuations for oil and gas have been particularly volatile in recent years due to supply and demand factors, worldwide energy conservation measures, OPEC and OPEC+ actions, global conflicts in major oil producing regions, especially in Eastern Europe and the Middle East, and general economic cycles, among other factors. These events and conditions have, at times, resulted in a reduction of global economic activity and volatility in the global financial markets. The scale and duration of the impact of these factors remain unknowable but could lead to a decrease in our revenues and have a material impact on our business segments and earnings, cash flow and financial condition.

We are not an oil and gas producer. Our revenues from oil and gas royalties are subject to the actions of others.

We are not an oil and gas producer. Our oil and gas royalty revenue is derived primarily from perpetual non-participating oil and gas royalty interests that we have retained or oil and gas interests that we have acquired. As oil and gas wells age, their production capacity may decline absent additional investment. However, the owners and operators of the oil and gas wells make all decisions as to investments in, and production from, those wells and our royalties are dependent upon decisions made by those owners and operators, among other factors. Accordingly, a significant portion of our revenues is reliant on the management and actions of third parties, over whom we have no control. Such third parties may not take actions or make decisions that will be beneficial to us, which could result in adverse effects on our financial results and performance.

Our estimated proved developed producing (“PDP”) reserves are based on many assumptions that may prove to be inaccurate. Any inaccuracies in these estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of oil, gas, and NGL with precision. Oil and gas reserve engineering requires subjective estimates of underground accumulations of oil and gas and assumptions concerning future oil and gas prices, production levels, ultimate recoveries and operating and development costs. In estimating our PDP reserves, we and Ryder Scott Company, L.P. (“Ryder Scott”), an independent third-party petroleum engineering firm, must make various assumptions with respect to many matters that may prove to be incorrect, including:

• future oil, gas, and NGL prices;

• unexpected complications from offset well development;

• production rates;

• reservoir pressures, decline rates, drainage areas and reservoir limits;

• interpretation of subsurface conditions including geological and geophysical data;

• potential for water encroachment or mechanical failures;

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• levels and timing of capital expenditures, lease operating expenses, production taxes and income taxes, and availability of funds for such expenditures; and

• effects of government regulation.

If any of these assumptions prove to be incorrect, our estimates of PDP reserves, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

Estimates of our proved, developed and producing reserves and related valuations as of December 31, 2025 were prepared by Ryder Scott, which conducted a well-by-well review of all wells in which we have a mineral or royalty interest for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Our reserve estimates could differ materially from those reserve estimates of operators developing on our acreage. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, may result in the actual quantities of oil and gas that are ultimately recovered being different from our reserve estimates.

The loss of key members of our management team or difficulty attracting and retaining experienced technical personnel could reduce our competitiveness and prospects for future success.

The successful implementation of our strategies and handling of other issues integral to our future success depends, in part, on our experienced management team, including with respect to the business of TPWR. The loss of key members of our management team could have an adverse effect on our business. If we cannot retain our experienced personnel or attract additional experienced technical personnel, our ability to compete within our industry could be harmed.

Demand for TPWR’s products and services is substantially dependent on the levels of expenditures by our customers.

Demand for TPWR’s products and services is substantially dependent on demand and expenditures by our customers for the exploration, development and production of oil and gas reserves. These expenditures are generally dependent on our customers’ overall financial position, capital allocation priorities, and views of future oil and gas prices. Declines, as well as anticipated declines, in oil and gas prices have in the past resulted, and may in the future result, in lower capital expenditures, project modifications, delays or cancellations, general business disruptions, and delays in payment, or nonpayment, of amounts that are owed to us, which could in the future, adversely affect our earnings, cash flow and financial condition. The results of operations for the Water Services and Operations segment have been impacted from time to time by reduced development pacing and declines in expenditures by our customers in response to varying industry or global circumstances. Our results may continue to be impacted by producer discretion on development pacing and capital expenditures.

We face the risks of doing business in a new and rapidly evolving market for TPWR and may not be able to successfully address such risks and achieve acceptable levels of success or profits.

We have encountered and may continue to encounter the challenges, uncertainties and difficulties frequently experienced in a new and rapidly evolving market with respect to the business of TPWR, including, but not limited to:

• pricing pressure driven by new competition;

• volatile and/or unexpected operating and maintenance costs;

• lack of sufficient customers or loss of significant customers for the business of TPWR;

• increased regulation, including with respect to environmental and geological uses and impacts on industry operations; and

• uncertainty regarding outsourced third-parties providing water treatment services.

The market in which TPWR operates is highly competitive and includes numerous companies capable of competing effectively on a local basis. TPWR competes with landowners, water supply and transfer companies, and companies who engage in the sale or treatment of produced water. Some of our larger diversified competitors have a broad geographic scope and have benefits of scale, while others focus on specific areas only and may have locally competitive cost efficiencies as a result.

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Additionally, there may be new companies that enter the water solutions business, or our existing and potential customers may develop their own water management solutions. Our ability to maintain current revenue and cash flows, and our ability to expand our operations, could be adversely affected by the activities of our competitors and our customers.

The impact of government regulation on TPWR could adversely affect our business.

The business of TPWR is subject to applicable state and federal laws and regulations, including laws and regulations on water use, environmental and safety matters. These laws and regulations may increase the costs and timing of planning, designing, drilling, installing, operating and abandoning water wells and sourced water and treatment facilities and impact our customers’ ability to transport, store and/or dispose of produced water in certain locations. Some state and local governmental authorities have begun to monitor or restrict the use of water to ensure adequate local water supply. In addition, due to increased seismicity in the Delaware and Midland Basins, the Texas Railroad Commission recently began implementing seismic response areas (“SRAs”) limiting the permitted capacity and use of certain saltwater disposal wells (“SWDs”) for the injection of produced water. For example, in January 2024, the Railroad Commission of Texas indefinitely suspended all deep oil and gas produced water injections in Culberson and Reeves counties. The implementation of SRAs could limit the volume of produced water disposed on the Company’s surface within the SRAs or, in certain cases, could direct additional volumes of produced water to SWDs on the Company’s surface outside of SRAs. These limitations and/or redirections may require TPWR to adapt its business plans and could affect TPWR’s financial performance. We continue to actively engage with the Texas Railroad Commission and evaluate the potential effect of SRAs on our produced water royalties.

Our produced water desalination project creates risks related to invested capital, environmental exposure and our reputation.

Through Transmissive, we are developing a proprietary produced water desalination technology and advancing the beneficial reuse process. Development of a produced water treatment facility requires substantial capital and may result in total project costs exceeding initial estimates due to inflation, supply chain constraints, labor and equipment availability, design changes, regulatory requirements or technical challenges. Delays in permitting, produced water sourcing, waste disposal arrangements, construction or commissioning could defer or reduce expected cash flows and impair the anticipated return on our investment. Actual throughput, pricing, operating costs and utilization may also differ from forecasts because they depend on competing treatment or disposal options, and changes in environmental or water‑handling regulations. As a result, Transmissive may fail to achieve targeted returns or require additional unplanned capital, which could lead to impairments of invested capital and have a material adverse effect on our business, financial condition, results of operations and liquidity.

We are exposed to the risk that discharges of treated water and treatment‑related waste, including those made in compliance with permitted limits, may have unforeseen adverse environmental effects. Material failures to properly treat, handle or transport produced water or discharge treated water, including leaks, spills or non‑compliance with discharge permits and performance standards, could risk contaminating surface waters, groundwater or navigable waters or damage natural resources. Such material failures could also trigger enforcement actions, require remediation or corrective measures, lead to operational restrictions or permit suspension or revocation, harm our reputation or result in third‑party claims for personal injury, property damage and other losses, any of which could materially and adversely affect our business, financial condition, results of operations and liquidity.

Negative public opinion or adverse perceptions of Transmissive’s operations or reputation could materially affect our business, results of operations, or prospects over time. Negative sentiment may arise from unfavorable portrayals of produced water, water treatment operations or discharge locations by the media, special interest groups, political leaders, stakeholders, or other parties, including organized opposition to specific projects or the energy industry in general. Potential impacts of such sentiment include operational delays or interruptions, legal or regulatory challenges, blockades, increased regulatory oversight, reduced public or governmental support, and the delay, challenge, or revocation of regulatory approvals, permits, or licenses, each of which may increase costs or cause cost overruns.

Our revenues from the sale of land are subject to substantial fluctuation. Land sales are subject to many factors that are beyond our control.

Our land sales vary widely from year to year and quarter to quarter. The total price obtained, the average price per acre, and the number of acres sold in any one year or quarter should not be assumed to be indicative of future land sales. Our desire to sell and the demand and pricing for any particular tract of our land is influenced by many factors, including but not limited to: (i) access and location, (ii) the national and local economies, (iii) the rate of oil and gas well development by operators, (iv) the rate of development in nearby areas, (v) the livestock carrying capacity, and (vi) the condition of the local

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industries, which itself is influenced by a range of conditions. Our ability to sell land can be, therefore, largely dependent on the actions of adjoining landowners.

A third party has refused to continue to fulfill its obligations under existing arrangements to which the Trust was a party in connection with the completion of our Corporate Reorganization, and thereby may cause us to lose certain benefits that the Trust historically received.

The completion of the Corporate Reorganization implicated conditions and covenants contained in certain agreements to which the Trust was, and now TPL is, a party and thereby may cause us to lose certain benefits that the Trust historically received. For example, the obligation to pay ad valorem taxes with respect to certain of our royalty interests was assumed by a third party and is now the obligation of the successors in interest to such third party, so long as such royalty interests are held by the Trustees or their successors in office under the Declaration of Trust. We have received an indication from one such obligor that it does not intend to continue to make ad valorem tax payments related to historical royalty interests. In order to protect the historical royalty interests from any potential tax liens for non-payment of ad valorem taxes, we have accrued and/or paid such ad valorem taxes since January 1, 2022. While we intend to seek reimbursement from the third party following payment of such taxes, there can be no assurance that we will be successful in getting reimbursed, and accordingly, no loss recovery receivable has been recorded as of December 31, 2025. Taking on the cost of such payments will have an adverse impact on our business and results of operations.

Our Credit Facility may limit our operating flexibility or otherwise adversely affect our business.

The Credit Facility contains customary affirmative and negative covenants that, among other things, limit our ability to grant liens, incur debt, make investments, effect certain mergers, dispose of assets, make certain payments, pay dividends or distributions on our capital stock, change the nature of our business, enter into certain transactions with affiliates, enter into certain burdensome agreements, enter into swap agreements and enter into sale and leaseback transactions, in each case subject to customary exceptions. We therefore may not be able to engage in any of the foregoing transactions unless we obtain the consent of the required lenders and administrative agent under the Credit Facility or terminate the Credit Facility. Our inability to engage in such actions could limit our operating flexibility and prohibit us from taking certain actions that might be beneficial to our business. Additionally, we are required to maintain as of the end of each fiscal quarter a consolidated interest coverage ratio of not less than 3.0 to 1.0 and a consolidated total leverage ratio of not greater than 3.50 to 1.0. Borrowings under the Credit Facility are initially unsecured, with a springing senior security interest in substantially all of the equity securities of our subsidiaries in the event our consolidated total leverage ratio exceeds 2.50 to 1.0. There is no guarantee that we will be able to generate sufficient cash flow to comply with these financial covenants or pay the principal and interest on any debt we incur under the Credit Facility. Furthermore, there is no guarantee that future working capital, borrowings or equity financing will be available to repay or refinance any such debt. Any inability to make scheduled payments or comply with the covenants in our Credit Facility could result in the acceleration of the obligations thereunder and could adversely affect our business.

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. If an event of default occurs, the lenders under the Credit Facility may be entitled to terminate the commitments and letter of credit extensions, accelerate any outstanding indebtedness under the Credit Facility, require us to post cash collateral with respect to any letters of credit and exercise any additional rights and remedies under the Credit Facility. If our indebtedness is accelerated, we may not have sufficient funds available to pay the accelerated indebtedness or that we will have the ability to refinance the accelerated indebtedness on terms favorable to us or at all.

We may make minority investments, engage in joint ventures or make other strategic alliances with third parties that subject us to risks and uncertainties outside of our control.

As part of our business strategy, from time to time, we may make minority investments in the equity securities of companies, engage in joint ventures or make other strategic alliances with third parties that we do not control. For example, 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. In connection with our investment, we received an equity interest, warrants, and a right of first refusal to supply water to Bolt-affiliated projects and related infrastructure. We may contribute land and receive additional equity that may or may not increase in value or be liquid. Minority investments inherently involve a lesser degree of control over business operations, thereby potentially increasing the financial, legal, operational and/or compliance risks associated with the minority investment.

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To the extent we hold only a minority equity interest in a company, we may lack affirmative control rights, which may diminish our ability to influence the company’s affairs in a manner intended to enhance the value of our investment in the company. Our investment could become impaired if the majority stakeholders or the management of the company take risks or otherwise act in a manner that does not serve our interests. In addition, we could be subject to reputational harm if the company in which the investment is made makes business, financial or management decisions with which we do not agree. These circumstances could also lead to disputes and litigation with management or employees of the company in which the investment is made, or its other stockholders.

The companies in which we make investments may have indebtedness or equity securities, or may be permitted to incur indebtedness or to issue equity securities, which rank senior to our investment. We also may make investments in early-stage companies that depend on venture funding and are not profitable. In the event of insolvency, liquidation, dissolution, reorganization or bankruptcy of a company in which an investment is made, holders of debt instruments and securities ranking senior to our investment would typically be entitled to receive payment in full before distributions could be made in respect of our investment.

We may also enter into separate commercial arrangements with these companies similar to our strategic agreement with Bolt, whether before, concurrently with, or after making a minority investment. In certain cases, an underlying commercial arrangement may be a driving factor behind our investment. Such commercial arrangements may not further our business strategy as we expected, and we may not realize all the economic benefits expected from the commercial agreement or realize the expected return on our investments.

Cyber incidents or attacks targeting the systems and infrastructure used by us, our operators, other third parties with whom we do business or the oil and gas industry in general may adversely impact our operations, and if we are unable to obtain and maintain adequate protection of our data, our business may be adversely impacted.

We and our operators increasingly rely on information technology systems to operate our respective businesses, and the oil and gas industry depends on digital technologies in exploration, development, production, and processing activities. Our technologies, systems and networks, and those of the operators on our properties and our vendors, suppliers and other business partners, have in certain instances been, and may in the future become, the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary, personal and other information, or other disruption of business activities. Even without a direct breach of our systems, cybersecurity attacks on such third parties could adversely impact our business and reputation. In addition, certain cyber incidents, such as surveillance, may remain undetected for some period of time.

While we utilize various systems, procedures and controls to mitigate exposure to cybersecurity attacks and prevent cybersecurity incidents, such systems, procedures and controls may be breached as a result of third-party action, employee error, third-party or employee malfeasance or otherwise. Globally, cybersecurity attacks are increasing in number, and the threat actors are increasingly organized and well financed, or at times supported by state actors. In addition, geopolitical tensions or conflicts may create a heightened risk of cybersecurity attacks. Because the techniques used to obtain unauthorized access or to sabotage systems change frequently, we may not be able to anticipate these techniques and implement adequate preventative or protective measures.

Our cyber liability insurance coverage may not be sufficient or may not be available in the future on acceptable terms, or at all. In addition, our cyber liability insurance policy may cover only a portion of losses incurred in investigating or remediating a cybersecurity incident, if at all, and may not cover all claims made against us. As cybersecurity threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Any actual or perceived cybersecurity incident could adversely affect our business, financial position or results of operations.

Risks Related to Our Common Stock

The market price of our Common Stock may fluctuate significantly.

The market price of our Common Stock may fluctuate significantly due to a number of factors, some of which may be beyond our control, including, but not limited to:

• actual or anticipated fluctuations in our results of operations due to factors related to our business;

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• our quarterly or annual earnings, or those of other companies in our industry;

• changes to the regulatory and legal environment under which we operate;

• changes in accounting standards, policies, guidance, interpretations or principles;

• reports issued by securities analysts;

• changes in earnings estimates by securities analysts or our ability to meet those estimates;

• the operating and stock price performance of other comparable companies;

• investor perception of our Company and our industry;

• actual or anticipated fluctuations in commodities prices; and

• domestic and worldwide economic and geopolitical conditions.

We may not continue to pay dividends or to pay dividends at the same rate as previously paid.

The timing, declaration, amount of, and payment of any cash dividends to our stockholders is within the discretion of our Board and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with our Credit Facility or any future debt service obligations or other contractual obligations, legal requirements, regulatory constraints, industry practice, ability to access capital markets and other factors deemed relevant by the Board. These factors could result in a change in our current dividend policy.

We will evaluate whether to repurchase our outstanding Common Stock in the future and we cannot guarantee the timing or amount of share repurchases, if any.

On November 1, 2022, our Board approved a stock repurchase program, which became effective January 1, 2023, to purchase up to an aggregate of $250.0 million of our outstanding Common Stock. During the year ended December 31, 2025, the Company repurchased 27,000 outstanding shares of Common Stock for an aggregate purchase price of $8.4 million, which repurchased shares were placed in treasury. The Company opportunistically repurchases stock under the stock repurchase program with funds generated by cash from operations. The stock repurchase program may be suspended from time to time, modified, extended or discontinued by the Board at any time. Any future repurchase under the stock repurchase program will be within the discretion of our Board and will depend upon many factors, including market and business conditions, the trading price of our Common Stock, available cash and cash flow, capital requirements and the nature of other investment opportunities.

The issuance of additional Common Stock in the future would dilute other stockholders.

Holders of our Common Stock could be diluted because of equity issuances for proposed acquisitions or capital market transactions or equity awards proposed to be granted to our directors, officers and employees subject to any required vote of holders of our Common Stock under our amended and restated certificate of incorporation and our amended and restated bylaws (“the Bylaws”). We may issue stock-based awards, including annual awards, new hire awards and periodic retention awards, as applicable, to our directors, officers and other employees under any employee benefits plans we have adopted or may adopt, using newly issued shares rather than treasury shares as is currently our practice.

In addition, our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more series of preferred stock having such designations, powers, preferences, privileges and relative, participating, optional and special rights, and qualifications, limitations and restrictions as the Board may generally determine in its sole discretion. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our Common Stock. For example, we could grant the holders of preferred stock the right to elect members of the Board or to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences that we could assign to holders of preferred stock could affect the residual value of our Common Stock.

State law and anti-takeover provisions could enable our Board to resist a takeover attempt by a third party and limit the power of our stockholders.

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Our amended and restated certificate of incorporation, Bylaws and Delaware law contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with our Board rather than to attempt a hostile takeover. These provisions include, among others: (a) the ability of our remaining directors to fill vacancies on our Board; (b) the ability of our Board to adopt, amend or repeal bylaws; (c) rules regarding how stockholders may present proposals or nominate directors for election at stockholder meetings; and (d) the right of our Board to issue preferred stock without stockholder approval.

In addition, we are subject to Section 203 of the Delaware General Corporation Law, as amended (“DGCL”), which could have the effect of delaying or preventing a change of control that you may favor. Section 203 provides that, subject to limited exceptions, persons that acquire, or are affiliated with persons that acquire, more than 15% of the outstanding voting stock of a Delaware corporation may not engage in a business combination with that corporation, including by merger, consolidation or acquisitions of additional shares, for a three-year period following the date on which that person or any of its affiliates becomes the holder of more than 15% of the corporation’s outstanding voting stock.

We believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our Board and by providing our Board with more time to assess any acquisition proposal. These provisions are not intended to make the Company immune from takeovers; however, these provisions apply even if the offer may be considered beneficial by some stockholders and could delay or prevent an acquisition that our Board determines is not in the best interests of the Company and its stockholders. These provisions may also prevent or discourage attempts to remove and replace incumbent directors.

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware or the U.S. District Court for the Northern District of Texas as the sole and exclusive forums for certain types of actions and proceedings that may be initiated by our stockholders, which could discourage lawsuits against the Company and our directors and officers.

Our amended and restated certificate of incorporation provides that unless the Company otherwise determines, the Court of Chancery of the State of Delaware (or, if such court does not have jurisdiction, any state or federal court residing within the State of Delaware) or the U.S. District Court for the Northern District of Texas in Dallas, Texas (or, if such court does not have jurisdiction, any district court in Dallas County in the State of Texas) will be the sole and exclusive forums for any derivative action brought on our behalf, any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, employees or stockholders, any action or proceeding asserting a claim against us or any of our directors, officers, employees or agents arising pursuant to, or seeking to enforce any right, obligation or remedy under any provision of the DGCL, the laws of the State of Texas, the laws of the State of New York, our amended and restated certificate of incorporation or our Bylaws or any action asserting a claim against us or any of our directors, officers, employees or agents governed by the internal affairs doctrine, in each such case, subject to the applicable court having personal jurisdiction over the indispensable parties named as defendants in such action or proceeding. Our amended and restated certificate of incorporation also provides that unless our Board otherwise determines, the federal district courts of the United States will be the sole and exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act of 1933, as amended (the “Securities Act”).

To the fullest extent permitted by law, this exclusive forum provision will apply to state and federal law claims, including claims under the federal securities laws, including the Securities Act and the Exchange Act, although our stockholders will not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder. The enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that one or more parts of the exclusive forum provision in our amended and restated certificate of incorporation is inapplicable or unenforceable.

This exclusive forum provision may limit the ability of our stockholders to bring a claim in a judicial forum that such stockholders find favorable for disputes with the Company or our directors or officers, which may discourage such lawsuits against the Company and our directors and officers. Alternatively, if a court were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could negatively affect our business, results of operations and financial condition.

Risks Related to Our Industry

Our business and financial results could be disrupted by natural or human causes beyond our control .

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Our revenues depend on natural and environmental conditions with respect to operations that result in royalties to us, or that use our water services. Our business and financial results are therefore subject to disruption from natural or human causes beyond our control, including physical risks from severe storms, floods, droughts resulting in aquifer declines and other forms of severe weather, war, accidents, civil unrest, political events, fires, earthquakes, system failures, pipeline disruptions, environmental hazards such as oil and produced water spills, terrorist acts and epidemic or pandemic diseases, any of which could result in a material adverse effect on oil and gas production and, therefore, our results of operations.

Our business and financial results are subject to major trends in our industry, such as decarbonization, and may be adversely affected by future developments that are out of our control.

Much of the value of the land we own and upon which we receive royalties is based on the oil and gas reserves located there. Our revenues may be negatively affected by changes driven by trends such as decarbonization efforts. Such changes may relate to the types or sources of energy in demand, such as a shift to renewable sources of power generation (for example, wind and solar), along with ongoing changes in regulatory, investor, customer and consumer policies and preferences. The evolution of global energy sources is affected by factors out of our control, such as the pace of technological developments and related cost considerations, the levels of economic growth in different markets around the world and the adoption of climate change-related policies. In addition, the possibility of taxes on energy sources, including oil and gas, may affect the demand for crude oil and gas and the operating costs for third-party operators on our royalty properties.

Our business could be negatively affected as a result of the actions of activists.

Our business could be negatively affected as a result of stockholder activism, which could cause us to incur significant expense, hinder execution of our business strategy, and impact the trading value of our securities. In the past, we have been the subject of stockholder activism, and we are subject to the risks associated with any ongoing or future such activism. Stockholder activism, including potential proxy contests, requires significant time and attention by management and our Board, potentially interfering with our ability to execute our strategic plan. We have incurred, and may in the future be required to incur, significant legal fees and other expenses related to activist stockholder matters, and the attention of our management may be diverted by such activism. While we welcome our stockholders’ constructive input, stockholder actions may result in negative impacts to the Company. Any of these impacts could materially and adversely affect our business and operating results, and the market price of our Common Stock could be subject to significant fluctuation or otherwise be adversely affected by stockholder activism.

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 burden from us for well development), strong balance sheet, and liquidity position will help us navigate through potential commodity price volatility.

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.”