Item 1A. Risk Factors
Crude oil and natural gas prices are volatile and fluctuate in response to a number of factors; Lower prices could reduce the net proceeds payable to the Trust and Trust distributions.
The Trust’s income and monthly distributions are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil and natural gas, (ii) market uncertainty and (iii) a variety of additional factors that are beyond the Trustee’s control. As of March 16, 2026, the price of oil was $93.39 per barrel and the price of natural gas was $3.03 per million British thermal units (“MMBtu”). Factors that may impact future commodity prices, including the price of oil and natural gas, include but are not limited to:
political conditions in major oil producing regions, including the conflicts in Eastern Europe, the Middle East, and South America;
worldwide economic and geopolitical conditions;
weather conditions;
trade barriers and tariffs;
public health concerns, such as COVID-19;
the supply and price of domestic and foreign crude oil or natural gas;
the level of consumer demand;
the price and availability of and purchaser or consumer preference for alternative fuels;
the proximity to, and capacity of, transportation facilities;
the effect of worldwide energy conservation measures and governmental policies and regulatory incentives for investments in non-fossil fuel energy sources; and
the nature and extent of governmental regulation and taxation.
Although the Trustee cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, gas royalty income for a given period generally relates to production three months prior to the period and crude oil royalty income for a given period generally relates to production two months prior to the period and will generally approximate current market prices in the geographic region of the production at the time of production. When crude oil and natural gas prices decline, the Trust is affected in two ways. First, distributable income from the Underlying Properties is reduced. Second, exploration and development activity by operators on the Underlying Properties may decline as some projects may become uneconomic and are either delayed or eliminated. It is impossible to predict future crude oil and natural gas price movements, and this reduces the predictability of future cash distributions to Unit holders.
Increased production and development costs attributable to the Royalties will result in decreased Trust distributions unless revenues also increase.
Production and development costs attributable to the Royalties are deducted in the calculation of the Trust’s share of net proceeds. Accordingly, higher or lower production and development costs will directly decrease or increase the amount received by the Trust from the Royalties. Production and development costs are impacted by increases in commodity prices, both directly, through commodity price dependent costs, such as electricity, and indirectly, as a result of demand driven increases in costs of oilfield goods and services. For
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example, the costs of electricity that will be included in production and development costs deducted in calculating the Trust’s share of 2026 net proceeds could increase compared to the electrical costs incurred during 2025 if higher fuel surcharges are charged by the third party electricity provider in response to any increased costs of natural gas consumed to generate the electricity. These increased costs could reduce the Trust’s share of 2026 net proceeds below the level that would exist if such costs remained at the level experienced in 2025. Similarly, new or changes to existing laws or regulations with which the Underlying Properties must comply, including environmental regulations or regulation of injection and disposal wells in connection with concerns regarding seismic activity, could result in increased production or development costs. If production and development costs attributable to the Royalties exceed the gross proceeds related to production from the Underlying Properties, the Trust will not receive net proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional proceeds to repay the costs.
Proposed actions by certain Unit holders may have the effect of converting the Trust into a different type of investment, terminating the Trust, and/or permitting other changes to the Trust to occur that may not be acceptable to all Unit holders.
SoftVest, L.P., a Unit holder of the Trust, has a petition pending in District Court in Tarrant County, Texas, seeking to judicially modify the Trust indenture to eliminate certain supermajority voting requirements and prohibited amendments to the indenture. If SoftVest, L.P.’s petition is successful, the effect of such modification would be that any provision of the indenture could be amended by a majority in interest of Unit holders constituting a quorum at a meeting of Unit holders where a quorum is present. While providing greater flexibility to make changes that a majority of Units represented at a meeting are in support of, such a modification could have the result of permitting changes to be made to the Trust that holders of a majority of all outstanding Units are not actually in favor of. SoftVest has stated in documents filed with the SEC that if the judicial modification is successful, it believes the Trust should be converted into a publicly traded corporation or limited liability company to be effected by means of (a) the transfer of the Trust’s assets to a newly-formed corporation or limited liability company (“Newco”), (b) the subsequent distribution of Newco’s equity interests to Unit holders and (c) the termination of the Trust. SoftVest has stated that the proposed conversion would terminate the Trust’s status as a fixed investment trust that is taxed as a grantor trust for federal income tax purposes, and that Newco would be subject to tax at the entity level if it is a corporation (unlike a grantor trust that is not subject to tax at the Trust level). SoftVest also noted that Newco could be a limited liability company treated as a partnership for federal income tax purposes, which would not be subject to tax at the entity level. Any modifications to the Trust’s classification for federal (and applicable state and local) income tax purposes would result in additional costs incurred by the Trust to implement and maintain new reporting procedures, which could result in reduced distributions to Unit holders. Additionally, other changes could be made to the Trust indenture that currently require a supermajority vote, or are prohibited, including distributions, distributing the Royalties in kind, altering the rights of Unit holders vis-à-vis each other, changing the purpose of the Trust, selling the assets of the Trust, or the Trust. Any or all of these changes may not be acceptable to all Unit holders.
Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both estimated reserves and estimated future net revenues to be too high, leading to write-downs of estimated reserves.
The value of the Units will depend upon, among other things, the reserves attributable to the Royalties from the Underlying Properties. The calculations of proved reserves and estimating reserves is inherently uncertain. In addition, the estimates of future net revenues are based upon various assumptions regarding future production levels, prices and costs that may prove to be incorrect over time.
The accuracy of any reserve estimate is a function of the quality of available data, engineering interpretation and judgment and the assumptions used regarding the quantities of recoverable crude oil and natural gas and the future prices of crude oil and natural gas. Petroleum engineers consider many factors and make many assumptions in estimating reserves. Those factors and assumptions include:
historical production from the area compared with production rates from similar producing areas;
the effects of governmental regulation;
assumptions about future commodity prices, production and development costs, taxes, and capital expenditures;
the availability of enhanced recovery techniques; and
relationships with landowners, working interest partners, pipeline companies and others.
Blackbeard does not provide any forward looking information regarding future-development and capital expenditures such that the reserve estimates as of December 31, 2024 and forward exclude all proved undeveloped reserves ("PUDs"). SEC rules, subject to limited exceptions, permit PUDs to be disclosed only if they relate to wells scheduled to be drilled within five years after the date of disclosure. Without a development plan reflecting development of wells, the Trust cannot disclose PUDs from the Waddell Ranch properties.
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Changes in any of these factors and assumptions can materially change reserve and future net revenue estimates. The Trust’s estimate of reserves and future net revenues is further complicated because the Trust holds an interest in net overriding royalties and does not own a specific percentage of the crude oil or natural gas reserves. Ultimately, actual production, revenues and expenditures for the Underlying Properties, and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-downs of reserves.
The assets of the Trust are depleting assets and, if the operators developing the Underlying Properties do not perform additional development projects, the assets may deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets. In addition, a reduction in depletion tax benefits may reduce the market value of the Units.
The net proceeds payable to the Trust are derived from the sale of depleting assets. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the Underlying Properties will affect the quantity of proved reserves and can offset the reduction in proved reserves. The timing and size of these projects will depend on the market prices of crude oil and natural gas. If the operators developing the Underlying Properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust. Blackbeard has refused to provide its future development plans of the Underlying Properties to the Trustee.
Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of distributions to Unit holders attributable to depletion may be considered a return of capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the Unit holders, which could reduce the market value of the Units over time. Eventually, the Royalties will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds therefrom.
Government action, policies or regulations designed to discourage production of, reduce demand for, or promote alternatives to oil and natural gas could impact the price of oil and natural gas produced on the Underlying Properties, directly as intended or through unintended consequences.
Governments around the world are considering actions intended to reduce greenhouse gas emissions by decreasing both the supply of and the demand for oil and natural gas products or by promoting alternatives. These include the adoption of cap and trade regimes, carbon taxes, trade tariffs, minimum renewable usage requirements, restrictive permitting, increased mileage and other efficiency standards, mandates for sales of electric vehicles, mandates for use of specific fuels or technologies, and other incentives or mandates designed to support transitioning to lower-emission energy sources. Political and other actors and their agents also increasingly seek to advance climate change objectives indirectly, such as by seeking to reduce the availability or increase the cost of financing and investment in the oil and gas sector. Depending on how policies are formulated and applied, such policies could impact the ability and costs of the operators of the Underlying Properties to supply products, demand for their products, or the competitiveness of hydrocarbon-based products, which in turn, could reduce royalty income to the Trust. Any policy that increases the costs for operators of the Underlying Properties or decreases market prices could have a material impact on the distributable income of the Trust.
The Trustee may be subject to attempted cybersecurity disruptions from a variety of sources including state-sponsored actors.
The Trustee maintains robust cybersecurity protocols including, but not limited to technological capabilities that prevent and detect disruptions; computer workstations and programs protected with passwords and passphrases, as well as employee training throughout the year on financial regulations and cybersecurity followed up by testing of that knowledge. Other, non-technical protocols include securing of documents and work areas that could contain personal, non-public information and independent verification of information changes by outside vendors. If the measures taken to protect against cybersecurity disruptions prove to be insufficient or if proprietary data is otherwise not protected, the Trustee, or customer, employees, or third parties could be adversely affected. The Trust is also exposed to potential harm from cybersecurity events that may affect the operations of third-parties, including suppliers, service providers (including providers of cloud-hosting services for our data or applications), and customers. Cybersecurity disruptions could cause physical harm to people or the environment, or assets; compromise business systems; result in proprietary information being altered, , or ; result in employee, customer, or third-party information being compromised; or otherwise business operations. The Trust could incur significant costs to remedy the effects of a major cybersecurity in addition to costs in connection with resulting regulatory actions, , or reputational .
Future royalty income may be subject to risks relating to the creditworthiness of third parties.
The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trust’s risk from credit markets. The Trust’s future royalty income, however, may be subject to risks relating to the creditworthiness of the operators of
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the Underlying Properties and other purchasers of the crude oil and natural gas produced from the Underlying Properties, as well as risks associated with fluctuations in the price of crude oil and natural gas.
The market price for the Units may not reflect the value of the royalty interests held by the Trust.
The public trading price for the Units tends to be tied to the recent and expected levels of cash distribution on the Units. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for crude oil and natural gas produced from the Royalties. The market price is not necessarily indicative of the value that the Trust would realize if it sold those Royalties to a third-party buyer. In addition, such market price is not necessarily reflective of the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a Unit holder over the life of these depleting assets will equal or exceed the purchase price paid by the Unit holder.
Operational risks and hazards associated with the development of the Underlying Properties may decrease Trust distributions.
There are operational risks and hazards associated with the production and transportation of crude oil and natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of crude oil or natural gas, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment or natural resources, or cleanup or remediation obligations. The operation of oil and gas properties is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of these or similar occurrences could be deducted as a cost of production in calculating the net proceeds payable to the Trust and would therefore reduce Trust distributions by the amount of such costs.
As of December 31, 2023, oil and gas production from the Waddell Ranch properties was processed through two facilities. Blackbeard has refused to verify if this information is still accurate as of December 31, 2024 and 2025. Should this number still be accurate, the limited number of gas processing facilities for the Waddell Ranch properties may impact future distributions from those properties as they may be particularly susceptible to operational risks and hazards. For example, a partial or complete shut down of operations at that facility could disrupt the flow of royalty payments to the Trust and, accordingly, the Trust’s distributions to its Unit holders. In addition, although Blackbeard is the current operator of record of the properties burdened by the Waddell Ranch overriding royalty interests, none of the Trustee, the Unit holders or Blackbeard, as the current operator, has an operating interest in the properties burdened by the Texas Royalty properties’ (as defined herein) overriding royalty interests. As a result, these parties are not in a position to eliminate or mitigate the above or similar occurrences with respect to such properties and may not become aware of such occurrences prior to any reduction in Trust distributions which may result therefrom.
Increased concerns about climate change and environmental sustainability could have an impact on development of the Underlying Properties.
There is considerable debate as to the environmental effects of greenhouse gas emissions and associated consequences affecting global climate, oceans, and ecosystems. We are not in a position to validate or repudiate the existence of climate change or various aspects of the scientific debate. However, climate change could have an impact on the operation of the Underlying Properties. Underlying Properties in areas with limited water availability may be particularly impacted if droughts become more frequent or severe. Similarly, more extreme weather events such as ice storms or extended periods of freezing or high temperatures could disrupt operation and production of the Underlying Properties. Changes in climate or weather may hinder exploration and production activities or increase or decrease the cost of production of oil and natural gas resources and consequently affect demand. Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix. However, we are not in a position to predict the precise effects of climate change on energy markets or the physical effects of climate change. We are providing this disclosure based on publicly available information on the matter.
It should be noted that, recently, concerns about the potential effects of climate change have resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. These concerns have also led to the oil and gas industry facing growing demand for corporate transparency and a demonstrated commitment to sustainability goals. Furthermore, in March 2024 the U.S. Securities and Exchange Commission (“SEC”) adopted rule amendments that would require public companies to disclose certain climate-related information in their public filings. The new rules also required certain disclosure requirements related to severe weather events and other natural conditions in a company's audited financial statements. However, the SEC stayed implementation of the rules until legal challenges to the rules could be resolved, and following installation of the second Trump presidential administration, is reassessing its position in the litigation. Accordingly, the SEC rules have not yet gone into effect. Environmental, social, and governance (“ESG”) goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have also become an increasing focus of investors and
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shareholders across the industry. While reporting on ESG metrics remains voluntary in the U.S., access to capital and investors is likely to favor companies with robust ESG programs in place. If participation in these initiatives becomes more common across the industry or if the rulemakings are ultimately reinstated or amended to require ESG-related disclosures, they could increase operational costs and make it more difficult for companies, including the companies that operate the Underlying Properties, to secure funding for exploration and production activities.
From a global perspective, the International Energy Agency (“IEA”) observed in its World Energy Outlook 2025 that global electricity demand continued to grow in 2024 and all energy sources, including renewable power and each of the fossil fuels, grew to meet that demand, which stemmed from emerging market and developing economies. Renewable power generation constituted 70% of the energy sources that met that demand and renewables grow faster than any other energy source in each of the IEA World Outlook current policies, stated policies, net zero emissions by 2050, and accelerating clean cooking and electricity services scenarios. The IEA notes the uncertainty in the energy sector related to global policy and trade and the value of energy supply diversification and supply chain resilience, particularly in light of increased geopolitical competition and conflict. In the last year, the U.S. has diminished its backing of wind, solar and electric vehicles, and increased its support of domestic fossil fuels and nuclear energy. Further, while the IEA noted an increase in the number of countries adopting renewable energy policies and energy performance standards, including vehicle fuel economy standards and energy performance standards for appliances and industrial motors, in the 2010s, those adoptions have somewhat flattened during the 2020s. The IEA also indicates momentum for national and international efforts to reduce emissions appears to have slowed. With the increase in geopolitical uncertainty and current energy market , countries feeling are increasingly focusing on their energy security policies, such as emergency stock oil requirements. The adoption and implementation of any international, federal, or state GHG-emission reduction commitments, legislation or regulations or other restrictions or imposition of taxes, fees, or limits on emissions of GHGs could result in increased development, operation, and compliance costs, additional operating restrictions on the Underlying Properties, and additional regulatory , and thus decrease revenue to the Trust.
Terrorism, continued hostilities in Eastern Europe, the Middle East, and South America or other military campaigns could decrease Trust distributions or the market price of the Units.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism, continued hostilities in Eastern Europe, the Middle East, or South America or other sustained military campaigns could adversely affect Trust distributions or the market price of the Units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which the operators developing the Underlying Properties rely could be a direct target or an indirect casualty of an act of terror.
Unit holders and the Trustee have no influence over the operations on, or future development of, the Underlying Properties.
Neither the Trustee nor the Unit holders can influence or control the operations on, or future development of, the Underlying Properties. The failure of an operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable to the Trust. The current operators developing the Underlying Properties are under no obligation to continue operations on the Underlying Properties. Neither the Trustee nor the Unit holders have the right to replace an operator.
The Units may lose value and cash available for distribution may be reduced as a result of title deficiencies with respect to the Royalty Properties.
The existence of a title deficiency with respect to any of the Royalty Properties could reduce the value or render a property worthless, thus adversely affecting the distributions to Unit holders. An operator’s inability or failure to cure title defects could cause the operator to lose its rights to some or all production from some of the Royalty Properties, which could result in a reduction in proceeds available for distribution to Unit holders and the value of the Units may be reduced.
Changes in the information historically made available to the Trustee by Blackbeard has delayed and will continue to delay Trust distributions
Since May 2024, Blackbeard has provided the Trustee information necessary to calculate the monthly net proceeds from the Waddell Ranch properties after the NYSE notification date for each monthly distribution. As a result, distribution of net proceeds from the Waddell Ranch properties each month has been delayed by a month such that distribution and reporting of distributions will remain one month in arrears.
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The operators developing the Texas Royalty properties have no duty to protect the interests of the Unit holders and do not have sole discretion regarding development activities on the Underlying Properties.
Under the terms of a typical operating agreement relating to oil and gas properties, the operator owes a duty to working interest owners to conduct its operations on the properties in a good and workmanlike manner and in accordance with its best judgment of what a prudent operator would do under the same or similar circumstances. Blackbeard is currently the operator of record of the Waddell Ranch overriding royalty interests and in such capacity owes the Trust a contractual duty under the conveyance agreement for that overriding royalty interest to operate the Waddell Ranch properties in good faith and in accordance with a prudent operator standard. The operators of the properties burdened by the Texas Royalty properties’ overriding royalty interests, however, have no contractual or fiduciary duty to protect the interests of the Trust or the Unit holders other than indirectly through its duty of prudent operations to the unaffiliated owners of the working interests in those properties.
In addition, even if an operator, including Blackbeard in the current case of the Waddell Ranch properties (as defined herein), concludes that a particular development operation is prudent on a property, it may be unable to undertake such activity unless it is approved by the requisite approval of the working interest owners of such properties (typically the owners of at least a majority of the working interests). Even if the Trust concludes that such activities in respect of any of its overriding royalty interests would be in its best interests, it has no right to cause those activities to be undertaken.
The operator developing any Underlying Property may transfer its interest in the property without the consent of the Trust or the Unit holders.
Any operator developing any of the Underlying Properties may at any time transfer all or part of its interest in the Underlying Properties to another party. Neither the Trust nor the Unit holders are entitled to vote on any transfer of the properties underlying the Royalties, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the transferred property will continue to be subject to the Royalties, but the net proceeds from the transferred property will be calculated separately and paid by the transferee. The transferee will be responsible for all of the transferor’s obligations relating to calculating, reporting and paying to the Trust the Royalties from the transferred property, and the transferor will have no continuing obligation to the Trust for that property.
The operator developing any Underlying Property may abandon the property, thereby terminating the Royalties payable to the Trust.
The operators developing the Underlying Properties, or any transferee thereof, may abandon any well or property without the consent of the Trust or the Unit holders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the Royalties relating to the abandoned well or property.
The Royalties can be sold and the Trust would be terminated.
The Trustee must sell the Royalties if the holders of 75% or more of the Units approve the sale or vote to terminate the Trust. The Trustee must also sell the Royalties if they fail to generate net revenue for the Trust of at least $1,000,000 per year over any consecutive two-year period. Sale of all of the Royalties will terminate the Trust. The net proceeds of any sale will be distributed to the Unit holders. The sale of the remaining Royalties and the termination of the Trust will be taxable events to the Unit holders. Generally, Unit holders will realize gain or loss equal to the difference between the amount realized on the sale and termination of the Trust and their adjusted basis in such Units. Gain or loss realized by a Unit holder who is not a dealer with respect to such Units and who has a holding period for the Units of more than one year will be treated as long-term capital gain or except to the extent of any recapture amount, which must be treated as ordinary income. Other federal and state tax issues concerning the Trust are discussed under Note 5 and Note 8 to the Trust’s financial statements, which are included herein. Each Unit holder should consult his, her or its own tax advisor regarding Trust tax compliance matters, including federal and state tax implications concerning the sale of the Royalties and the of the Trust.
Unit holders have limited voting rights and have limited ability to enforce the Trust’s rights against the current or future operators developing the Underlying Properties.
The voting rights of a Unit holder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unit holders or for an annual or other periodic re-election of the Trustee.
The Trust indenture and related trust law permit the Trustee and the Trust to sue Blackbeard, Riverhill Energy Corporation or any other future operators developing the Underlying Properties to compel them to fulfill the terms of the conveyance of the Royalties. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the Unit holders would likely be
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limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Unit holders probably would not be able to sue Blackbeard, Riverhill Energy Corporation or any other future operators developing the Underlying Properties.
Financial information of the Trust is not prepared in accordance with GAAP.
The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States (“GAAP”). Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from GAAP financial statements mainly because revenues are not accrued in the month of production and cash reserves may be established for specified contingencies and deducted which could not be recorded in GAAP financial statements. Further, Trust expenses are recorded when paid and not in the month they were incurred.
The limited liability of the Unit holders is uncertain.
The Unit holders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a corporation’s liabilities. The structure of the Trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to Unit holders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to insure that such liabilities are to be satisfied only out of Trust assets, under the laws of Texas, which are unsettled on this point, a holder of Units may be jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a result, Unit holders may be exposed to personal liability.
The tax treatment of an investment in Trust Units could be affected by recent and potential legislative changes, possibly on a retroactive basis.
U.S. federal tax reform legislation known as the Tax Cuts and Jobs Act (the “TCJA”) was enacted December 22, 2017, and made significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the effective tax rate on a Unit holder’s allocable share of certain income from the Trust. Additionally, the One Big Beautiful Bill Act (“OBBBA”) was signed into law on July 4, 2025 and, among other items, made permanent, extended or modified certain provisions under the TCJA. The TCJA and OBBA are complex, thus, Unit holders should consult their tax advisor regarding the TCJA and OBBA and their effect on an investment in Trust Units.
Any modification to the U.S. federal income tax laws or interpretations thereof (including administrative guidance relating to the TCJA or OBBA) may be applied retroactively and could adversely affect the Trust’s business, financial condition or results of operations. The Trust is unable to predict whether any changes or other proposals will ultimately be enacted, or whether any adverse interpretations will be issued. Any such changes or interpretations could negatively impact the value of an investment in the Trust Units.
Pandemics or other public health concerns, such as COVID-19, or the novel coronavirus, and any measures taken to mitigate such health concerns, could adversely affect the business and operations of the operators of the Waddell Ranch properties and the Texas Royalty properties, which in turn could have an adverse effect on Trust distributions.
Demand for oil and gas, and the business and operations of the operators of the properties underlying the net profits interests, had and may in the future be adversely impacted by public health concerns such as the COVID-19 pandemic and measures taken to mitigate its impact. The industry experienced a sharp and rapid decline in the demand for crude oil and natural gas as the U.S. and global economy in 2020, and commodity prices were negatively impacted as economic activity was curtailed in response to the COVID-19 pandemic, as well as due to other geopolitical factors. Future pandemics or other significant public health events could have a material adverse effect on the operators’ business and financial condition which would likely have an adverse effect on trust distributions.
Item 1B. Unresolved S taff Comments
The Trust has not received any written comments from the SEC staff regarding its periodic or current reports under the Act not less than 180 days before December 31, 2025, which comments remain unresolved.
Item 1C. Cybe rsecurity.
The Trust does not have a board of directors; therefore, the Trustee is responsible for oversight of the Trust’s risks from cybersecurity threats. The Trustee has dedicated personnel responsible for assessing and managing the Trust’s cyber risk management program, informing senior management of the Trustee regarding the prevention, detection, mitigation, and remediation of cybersecurity
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incidents and supervising such efforts. The Trustee’s information technology team has decades of experience selecting, deploying, and operating cybersecurity technologies, initiatives, and processes, and relies on threat intelligence as well as other information obtained from governmental, public or private sources, including external consultants engaged by the Trustee to monitor the prevention, detection, mitigation, and remediation of cybersecurity incidents. External partners are a key part of the Trustee’s cybersecurity protocols and policies. The Trustee works with leading firms in the cybersecurity industry, leveraging their technology and expertise to monitor and maintain the performance and effectiveness of products and services that are used by the Trustee.
The Trustee maintains a cyber risk management program designed to identify, assess, manage, mitigate, and respond to cybersecurity threats, which processes are integrated into the Trustee’s overall risk management process. The Trustee maintains robust cybersecurity protocols including, but not limited to technological capabilities that prevent and detect disruptions; computer workstations and programs protected with passwords and passphrases, as well as employee training throughout the year on financial regulations and cybersecurity followed up by testing of that knowledge. The protocols are based on recognized best practices and standards for cybersecurity and information technology. The Trustee has an annual assessment, performed by a third party vendor, of the Trustee’s cyber risk management program.
Other non-technical protocols include securing of documents and work areas that could contain personal, non-public information and independent verification of information changes by outside vendors.
The Trust faces risks from cybersecurity threats that could have a material adverse effect on its business, financial condition, results of operations, cash flows or reputation. The Trustee has experienced, and will continue to experience, cyber incidents in the normal course of its business. However, prior cybersecurity incidents have not had a material adverse effect on the Trust’s business, financial condition, results of operations, or cash flows. See Item 1A “Risk Factors.”
Item 2. Prop erties
The Royalties include: (1) a 75% net overriding royalty carved out of Southland Royalty’s fee mineral interests in the Waddell Ranch in Crane County, Texas (the “Waddell Ranch properties”); and (2) a 95% net overriding royalty carved out of Southland Royalty’s major producing royalty interests in Texas (the “Texas Royalty properties”). The interests out of which the Trust’s net overriding royalty interests were carved were in all cases less than 100%. The Trust’s net overriding royalty interests represent burdens against the properties in favor of the Trust without regard to ownership of the properties from which the overriding royalty interests were carved. The net overriding royalty for the Texas Royalty properties is subject to the provisions of the lease agreements under which such royalties were created. References below to “net” wells and acres are to the interests of the owner of the Underlying Properties (from which the Royalties were carved) in the “gross” wells and acres.
The following information under this Item 2 is based upon data and information, including computation statements, furnished to the Trustee by Blackbeard, the operator of the Waddell Ranch properties, and Riverhill Energy, the operator of the Texas Royalty properties.
PRODUCING ACREAGE, WELLS AND DRILLING
Waddell Ranch Properties . The net profits/overriding royalty interest in the Waddell Ranch properties is the largest asset of the Trust. The mineral interests in the Waddell Ranch, from which such net royalty interests are carved, vary from 37.5% (Trust net interest) to 50% (Trust net interest) in 78,715 gross (34,205 net) producing acres as of December 31, 2023, the most recent date for which the Trustee has information. A majority of the proved reserves are attributable to two fields, the Sand Hills and Waddell. There are 12 producing zones in these fields, and horizontal wells have been drilled in 11 of these zones over the past four years.
Proved reserves and estimated future net revenues attributable to the properties are included in the reserve reports summarized below. The owner of the Underlying Properties for Waddell Ranch does not own the full working interest in any of the tracts constituting the Waddell Ranch properties and, therefore, implementation of any development programs will require approvals of other working interest holders as well as the owner of the Underlying Properties. In addition, implementation of any development programs will be dependent upon certain factors including, but not limited to, oil and gas prices currently being received and anticipated to be received in the future, along with the development plans of the operators and owners of the Underlying Properties.
Development information for the Waddell Ranch properties such as well completions, workovers, remedial activities, and plugging and abandonment, is not provided by Blackbeard.
Based on the quarterly reports provided by Blackbeard, the total amount of capital expenditures reported for the months of December 2024 through November of 2025 with regard to the Waddell Ranch properties totaled $228.7 million (gross). Capital
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expenditures do not include the cost of remedial and maintenance activities. The amount spent on remedial and maintenance activities was approximately $21 million for the 12 months included in the 2025 quarterly reports.
The Trustee has been advised that, effective November 1, 2019, BROG sold its interests in the Waddell Ranch properties to Blackbeard. In conjunction with the transfer and assignment of the Waddell Ranch properties, BROG also assigned to Blackbeard all of its rights, title and interest in and to the Net Overriding Royalty Conveyance (Permian Basin Royalty Trust - Waddell Ranch) dated November 1, 1980. BROG handled all operations and accounting on behalf of Blackbeard until March 31, 2020.
Texas Royalty Properties . The Texas Royalty properties consist of royalty interests in mature producing oil fields, such as Yates, Wasson, Sand Hills, East Texas, Kelly-Snyder, Panhandle Regular, N. Cowden, Todd, Keystone, Kermit, McElroy, Howard-Glasscock, Seminole and others located in 33 counties across Texas. The Texas Royalty properties consist of approximately 125 separate royalty interests containing approximately 303,000 gross (approximately 51,000 net) producing acres. Approximately 35% of the future net revenues discounted at 10% attributable to Texas Royalty properties are located in the Wasson and Yates fields. Detailed information concerning the number of wells on royalty properties is not generally available to the owners of royalty interests. Consequently, an accurate count of the number of wells located on the Texas Royalty properties cannot readily be obtained.
In February 1997, BROG sold its interests in the Texas Royalty properties that are subject to the Net Overriding Royalty Conveyance to the Trust dated effective November 1, 1980 (“Texas Royalty Conveyance”) to Riverhill Energy Corporation (“Riverhill Energy”), which was then a wholly-owned subsidiary of Riverhill Capital and an affiliate of Coastal Management Corporation (“CMC”). The Trustee was informed by BROG that, as required by the Texas Royalty Conveyance, Riverhill Energy succeeded to all of the requirements upon, and the responsibilities of BROG under, the Texas Royalty Conveyance with regard to the Texas Royalty properties. BROG and Riverhill Energy further advised the Trustee that all accounting operations pertaining to the Texas Royalty properties were being performed by Riverhill Energy.
The Trustee has been advised that, effective April 1, 1998, Schlumberger Technology Corporation (“STC”) acquired all of the shares of stock of Riverhill Capital. Prior to the acquisition by STC, CMC and Riverhill Energy were wholly-owned subsidiaries of Riverhill Capital. The Trustee has further been advised, in accordance with the STC acquisition of Riverhill Capital, the shareholders of Riverhill Capital acquired ownership of all shares of stock of Riverhill Energy.
Effective January 1, 2001 CMC merged into STC. Thus, the ownership in the Texas Royalty properties remained in Riverhill Energy.
The Trustee has been advised that as of May 1, 2000, the accounting operations pertaining to the Texas Royalty properties were transferred from STC to Riverhill Energy.
Well Count and Acreage Summary . Information regarding the gross and net producing oil and gas wells and acres for the Blackbeard interests on the Waddell Ranch and Riverhill Energy’s interest in the Texas Royalty properties as of December 31, 2025 is not available.
OIL AND GAS PRODUCTION
The Trust recognizes production during the month in which the related distribution is received. As of May 2024, Blackbeard no longer provides the Trustee information necessary to calculate the net proceeds as of the NYSE notification date for the monthly distribution, such that oil and gas production for the calendar year 2024 is associated with actual production for 11 months from November 2023 through September 2024 and oil and gas production for the calendar year 2025 is associated with actual production for the 12 months of October 2024 through September 2025. Production for the Texas Royalty Properties is for the 12 months from November of the prior year through October of the current year for both 2024 and 2025. Production of oil and gas attributable to the Royalties and the Underlying Properties, the related average sales prices and the average production cost per unit of production
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attributable to the Underlying Properties for the three years ended December 31, 2025, excluding portions attributable to the adjustments discussed above, were as follows:
Waddell Ranch Properties
Texas Royalty Properties
Total
Royalties:
Production
Oil (barrels)
Gas (Mcf)
Underlying Properties:
Production
Oil (barrels)
Gas (Mcf)
Average Sales Price
Oil/barrel
Gas/Mcf
Average Production Cost Oil/Gas BOE
Since the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent on such factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison.
Waddell Ranch properties lease operating expense increased to $98 million (gross) in 2025 from $82 million (gross) for 2024. Lease operating expenses for 2023 were $80 million. A reason for the increase was not provided by Blackbeard. Waddell Ranch lifting cost on a barrel of oil equivalent (BOE) basis in 2025 was $18.54 per barrel (“bbl”) as compared to $21.39 per bbl in 2024 and $20.59 in 2023.
PRICING INFORMATION
Reference is made to the caption entitled “Regulation” for information as to federal regulation of prices of natural gas. The following paragraphs provide information regarding sales of oil and gas from the Waddell Ranch properties. As a royalty owner, Riverhill Energy is not furnished detailed information regarding sales of oil and gas from the Texas Royalty properties.
Oil. The Trustee has previously been advised by the operator that the majority of oil from the Waddell Ranch was pipeline connected and sold under long term crude purchase agreements. Blackbeard did not confirm whether this continues to be the case as of December 31, 2025.
Gas. The trustee has previously been advised by the operator that the majority of gas produced from Waddell Ranch properties was processed through Targa Resources Corporation Midway processing plant. Both residue gas and plant products were purchased by Targa who received fees (gathering, compression, treating, processing) and a percentage of the gas and liquids as compensation. Blackbeard did not confirm whether this continues to be the case as of December 31, 2025.
OIL AND GAS RESERVES
The following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this Item:
“Proved oil and gas reserves” are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
The area of the reservoir considered as proved includes:
The area identified by drilling and limited by fluid contacts, if any, and
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
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(iii)
Where direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
The project has been approved for development by all necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“Developed oil and gas reserves” are reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“Estimated future net revenues” are computed by applying average prices during the 12-month period prior to fiscal year-end determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. “Estimated future net revenues” are sometimes referred to herein as estimated future net cash flows.
“Present value of estimated future net revenues” is computed using the estimated future net revenues and a discount factor of 10%.
“Reserves” are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Undeveloped oil and gas reserves” are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in 17 CFR 210.4-10(a)(2), or by other evidence using reliable technology establishing reasonable certainty.
Blackbeard does not provide a development budget or any forwarding looking information. As a result, in contrast to prior years, the reserve estimates as of December 31, 2024 and December 31, 2025, exclude all proved undeveloped reserves due to lack of a development plan reflecting wells to be drilled. In 2023, the last year for which development plan information was available, the proved undeveloped reserves constituted 48.3% of the total proved reserves for the Waddell Ranch properties and 38% of the total proved reserves for the Trust.
The process of estimating oil and gas reserves is complex and requires significant judgment. As a result, the Trustee has developed internal policies and controls for estimating reserves. As described above, the Trust does not have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty interests. The
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Trustee gathers production information (which information is net to the Trust’s interests in the Underlying Properties) and provides such information to Cawley, Gillespie & Associates, Inc. (“CG&A”), who extrapolates from such information estimates of the reserves attributable to the Underlying Properties based on its expertise in the oil and gas fields where the Underlying Properties are situated, as well as publicly available information. The Trust’s policies regarding reserve estimates require proved reserves to be in compliance with the SEC definitions and guidance.
The independent petroleum engineers’ reports as to the proved oil and gas reserves attributable to the Royalties conveyed to the Trust were prepared by CG&A, whose firm registration number is F-693, was founded in 1961 and is nationally recognized in the evaluation of oil and natural gas properties. The technical person at CG&A primarily responsible for overseeing the reserves estimates with respect to the Trust is Zane Meekins. Mr. Meekins has been a practicing petroleum engineering consultant since 1989 with over 37 years of practice experience in petroleum engineering and is a registered professional engineer in the State of Texas (License No. 71055). Mr. Meekins graduated from Texas A&M University in 1987, S umma Cum Laude , with a B.S. degree in Petroleum Engineering. Both CG&A and Mr. Meekins have indicated that they meet or exceed all requirements set forth in Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Cawley, Gillespie & Associates, Inc.’s reports are attached as exhibits to this Form 10-K. The following table presents a reconciliation of proved reserve quantities from December 31, 2022 through December 31, 2025 (in thousands):
Waddell Ranch Properties
Texas Royalty Properties
Total
Oil
(Bbls)
Gas
(Mcf)
Oil
(Bbls)
Gas
(Mcf)
Oil
(Bbls)
Gas
(Mcf)
BOE
December 31, 2022
Extensions, discoveries, and other additions
Revisions of previous estimates
Production
December 31, 2023
Extensions, discoveries, and other additions
Revisions of previous estimates
Production
December 31, 2024
Extensions, discoveries, and other additions
Revisions of previous estimates
Production
December 31, 2025
Estimated quantities of proved reserves and net cash flow as of December 31, 2025 are as follows:
Waddell Ranch Properties
Oil
(Mstb)
Gas
(Mcf)
BOE
Net Cash
Flow, M$
10% Disc.
Cash
Flow, M$
Proved Developed Producing
Proved Developed
Total Proved
Texas Royalty Properties
Oil
(Mstb)
Gas
(Mcf)
BOE
Net Cash
Flow, M$
10% Disc.
Cash
Flow, M$
Proved Developed Producing
Proved Developed
Total Proved
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Total Waddell Ranch Plus Texas Royalty
Properties
Oil
(Mstb)
Gas
(Mcf)
BOE
Net Cash
Flow, M$
10% Disc.
Cash
Flow, M$
Proved Developed Producing
Proved Developed
Total Proved
Estimated quantities of proved developed reserves of oil and gas as of the dates indicated were as follows (in thousands):
Proved Developed Reserves:
Oil
(Barrels)
Gas
(Mcf)
BOE
December 31, 2022
December 31, 2023
December 31, 2024
December 31, 2025
The SEC requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and gas reserves.
Estimates of proved oil and gas reserves are by their very nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and gas and other variables.
The 2025, 2024 and 2023 change in the standardized measure of discounted future net cash revenues related to future royalty income from proved reserves attributable to the Royalties discounted at 10% is as follows (in thousands):
Waddell Ranch Properties
Texas Royalty Properties
Total
January 1
Extensions, discoveries,
and other additions
Accretion of discount
Revisions of previous
estimates and other
Royalty income
December 31
Average oil and gas prices of $65.34 per barrel and $3.387 per Mcf, respectively, were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties at December 31, 2025. The upward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties are primarily due to new drilling projects on the Waddell Ranch properties. The Texas Royalty properties are revised downward due to lower oil pricing.
Average oil and gas prices of $75.48 per barrel and $2.13 per Mcf, respectively, were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties at December 31, 2024 The downward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties are primarily due to exclusion of proved undeveloped reserves and weaker pricing for oil and gas. The Texas Royalty properties are revised downward due to The Texas Royalty properties are revised downward due to a significant reduction in gas sales from the Denver unit and weaker pricing for gas.
Average oil and gas prices of $78.22 per barrel and $2.64 per Mcf, respectively, were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties at December 31, 2023. The downward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties are primarily due to weaker pricing for oil and gas. The Texas Royalty properties are revised downward due to weaker pricing for oil.
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The following presents estimated future net revenue and the present value of estimated future net revenue attributable to the Royalties, for each of the years ended December 31, 2025, 2024 and 2023 (in thousands):
Estimated
Future Net
Revenue
Present
Value at
Estimated
Future Net
Revenue
Present
Value at
Estimated Future
Net Revenue
Present
Value at
Total Proved
Waddell Ranch properties
Texas Royalty properties
Total
Reserve quantities and revenues shown in the preceding tables for the Royalties were estimated from projections of reserves and revenue attributable to the combined Blackbeard, Riverhill Energy and Trust interests in the Waddell Ranch properties and Texas Royalty properties. Reserve quantities attributable to the Royalties were estimated by allocating to the Royalties a portion of the total estimated net reserve quantities of the interests, based upon gross revenue less production taxes. Because the reserve quantities attributable to the Royalties are estimated using an allocation of the reserves, any changes in prices or costs will result in changes in the estimated reserve quantities allocated to the Royalties. Therefore, the reserve quantities estimated will vary if different future price and cost assumptions occur.
Proved reserve quantities are estimates based on information available at the time of preparation and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of those reserves may be substantially different from the original estimate. Moreover, the present values shown above should not be considered as the market values of such oil and gas reserves or the costs that would be incurred to acquire equivalent reserves. A market value determination would include many additional factors.
Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate account of the number of wells located on the above royalty properties, the number of exploratory or development wells drilled on the above royalty properties during the periods presented by this report, or the number of wells in process or other present activities on the above royalty properties, and the Registrant cannot readily obtain such information.
REGULATION
Many aspects of the exploration and production, pricing, transportation and marketing of crude oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on affected members of the industry.
Exploration and production operations are subject to various types of regulation at the federal, tribal, state and local levels. Such regulation includes requiring permits for the drilling and production of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, controlling and remediating pollution from exploration and production activities, proper handling and disposal of waste generated from exploration and production operations, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally prohibit the venting and regulate the flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of natural gas and oil that can be produced, potentially to raise prices, and to limit the number of wells or the locations which can be drilled.
Federal Natural Gas Regulation
The Federal Energy Regulatory Commission (the “FERC”) is primarily responsible for federal regulation of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal governmental regulation, including regulation of transportation and storage tariffs and various other matters, by the FERC. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or the FERC rules, regulations or orders thereunder. Wellhead sales of domestic natural gas are not subject to regulation. Consequently, sales of natural gas may be made at market prices, subject to applicable contract provisions.
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Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation, and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry. The ultimate impact of the rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial decisions and final decisions by the FERC.
New proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Trust cannot predict when or if any such proposals might become effective, or their effect, if any, on the Trust. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. Crude oil prices are affected by a variety of factors. Since domestic crude price controls were lifted in 1981, the principal factors influencing the prices received by producers of domestic crude oil have been the pricing and production of the members of the Organization of Petroleum Export Countries (“OPEC”).
On December 19, 2007, President Bush signed into law the Energy Independence & Security Act of 2007 (PL 110 140)(the “EISA”). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder.
State Regulation
The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing, number, operation of wells and the prevention of waste of oil and gas resources, bonding or other financial assurance to drill or operate wells, decommissioning and removal of equipment, and the plugging and abandonment of wells. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a market demand or conservation basis, or both. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from the wells on the Underlying Properties, negatively affect the economics of production from these wells, or limit the number of wells or locations can be drilled.
Local Regulation
Drilling for and production and transportation of crude oil and natural gas are also regulated by local authorities. Local laws may include land use regulations, permitting requirements, and noise and traffic ordinances. Such regulation could increase drilling and production costs or create delays in development and production of the Underlying Properties.
Environmental Regulation
Companies in the oil and gas industry are subject to stringent and complex federal, tribal, state and local laws and regulations governing the health and safety aspects of oil and gas operations, the management and discharge of materials into the environment, or otherwise relating to environmental protection. Those laws and regulations may impose numerous obligations that are applicable to the operations of the Underlying Properties, including the acquisition of a permit before conducting drilling, production or underground injection activities; the restriction on the types, quantities and concentrations of materials that can be emitted or released into the environment; the limitation or prohibition of drilling or other construction or operational activities on certain lands lying within wilderness, wetlands, endangered or threatened species habitat, and other sensitive environments or protected areas; the installation of emission monitoring and/or pollution control equipment; the reporting of the types and quantities of various substances that are generated, stored, processed, released, or disposed of in connection with operation of the Underlying Properties; the remediation of pollution from current or former operations, such as cleanup of releases, pit closure, removal of surface equipment and plugging of wells; the sourcing and disposal of water used in the drilling, fracturing completion and production processes; the planning and preparedness for spill and emergency response activities; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations including waste generation, air emissions,
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water discharges and current and historical waste disposal practices. Failure to comply with these laws and regulations may result in the adverse modification, suspension or revocation of necessary permits, licenses and authorizations; the requirement that additional pollution controls be installed; the assessment of administrative, civil or criminal fines or penalties; the imposition of investigatory, ongoing monitoring, or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations. Under certain environmental laws and regulations, the operators of the Underlying Properties could also be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination, in either case, whether at a drilling or other operations site or a waste disposal facility, regardless of whether the operators were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken.
All of the jurisdictions in which the Underlying Properties are operated have statutory and administrative provisions regulating the exploration for and production of oil and natural gas, including, for example, provisions related to the sourcing and disposal of water used in the drilling and completion process, the control and permitting of air emissions from well completion and production operations, the management and disposal of wastes and wastewater (including produced water) generated from the operation of the Underlying Properties, decommissioning and removal of equipment, bonding to drill or operate wells, decommissioning and removal of equipment, and the plugging and abandonment of wells. Operation of the Underlying Properties is also subject to regulations that generally prohibit the venting or flaring of natural gas. The effect of such regulations may be to limit the amounts of oil and natural gas that may be produced from the wells on the Underlying Properties or negatively affect the economics of production from these wells.
In addition, climate change is the subject of an important public policy debate and the basis for new legislation proposed by the United States Congress and certain states. The United States, depending on which President has been in office, has participated (during the Biden administration) or not (during the two Trump administrations) in the Paris Climate Accord, a voluntary international agreement with the goal of limiting global climate change to not more than 2 degrees Celsius (or less). The Biden administration had also set ambitious domestic targets for curbing climate change, such as making the U.S. power sector carbon-neutral by 2035 and announcing a plan to achieve net-zero emissions from overall federal operations by 2050. While changes in U.S. presidential administrations could increase or lessen the relative impacts of climate policies and regulations on the oil and natural gas industry, the adoption and implementation of any international, federal, or state greenhouse gas (“GHG”)-emission reduction commitments, legislation, or regulations or other restrictions or imposition of taxes, fees, or limits on emissions of GHGs could result in increased development, operation, and compliance costs, additional operating restrictions on the Underlying Properties, and additional regulatory burdens, and thus decrease revenue to the Trust.
In response to the April 2007 U.S. Supreme Court decision in Massachusetts vs. EPA finding that greenhouse gases (“GHGs”) are air pollutants under the Clean Air Act (“CAA”), the United States Environmental Protection Agency (the “EPA”) issued an “Endangerment Finding” under Section 202(a) of the CAA, concluding that GHG pollution threatens the public health and welfare of future generations. Thereafter, EPA promulgated GHG monitoring and reporting regulations (the “GHG Reporting Rule”) that, since 2011, have required annual reporting of carbon dioxide, methane and nitrous oxide emissions from certain sources in the oil and natural gas industry sector, including in the onshore oil and natural gas production segment. The EPA indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG emission limits. In August 2022, Congress passed the Inflation Reduction Act, which included requirements to impose fees beginning in 2025 on 2024 calendar year methane emissions from oil and gas operations that are required to report their GHG emissions under the EPA’s GHG Reporting Rule. EPA’s final rule to implement the fee requirements, “Waste Emissions Charge for Petroleum and Natural Gas Systems” was published on November 18, 2024, and took effect on January 17, 2025. Compliance with these rules would have required enhanced record-keeping practices and, thus, may have increased operating costs associated with the Underlying Properties and may have decreased net revenue to the Trust. However, following the second Trump presidential inauguration, Congress collection of the Waste Emissions Charge until 2034 under the One Big Bill Act, which President Trump signed into law on July 4, 2025. And, consistent with that , EPA proposed on September 12, 2025, to all GHG reporting for the oil and gas sector (40 C.F.R. Part 98, Subpart W) until 2034. Further, on February 12, 2026, EPA rescinded the finding on the basis that EPA statutory authority under Section 202(a) of the CAA to prescribe standards for GHG emissions, thus creating additional uncertainty about the scope and extent of GHG regulation in the United States. If the GHG reporting rule is not permanently repealed and if the rescission of the finding is not upheld in the that promptly ensued, operating costs associated with GHG recordkeeping and reporting will continue to be incurred for the Royalty Properties. If GHG reporting, emission fees, reduction targets, or additional permitting are reinstated or imposed in the future, such requirements could decrease net revenue to the Trust.
In addition, on May 9, 2024, pursuant to its authority under Section 111 of the CAA to set emission standards for new and existing power plants based on the “best system of emission reduction,” EPA finalized new source performance standards for GHG emissions from fossil fuel-fired stationary combustion turbine electricity generating units and from certain fossil-fuel fired steam generating units. Among other requirements, the rule, effective July 8, 2024, revised CAA New Source Performance Standards (“NSPS”) for new or substantially modified natural gas-fired power plants based on the use of more efficient fuels, simple cycle operation, and the implementation of carbon capture and sequestration/storage technology. The rule also revises the NSPS for GHG emissions from fossil
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fuel–fired steam generating units that undertake major modifications. The rule was promptly challenged in court, and on June 11, 2025, EPA under the second Trump Administration proposed to repeal GHG emissions standards for fossil fuel-fired power plants and to make a finding that GHG emissions from fossil fuel-fired power plants do not contribute significantly to dangerous air pollution or, in the alternative, repeal certain other requirements, such as the emission guidelines for existing fossil fuel-fired steam generating units, and certain carbon capture and storage standards for coal-fired steam generating units and new base load stationary combustion turbines. Adoption of rules that either place additional limits on GHG emissions from fossil fuel-fired electricity or steam generating units or otherwise incentivize non-fossil fuel generated sources of energy could reduce demand for oil and gas generally, including oil and gas produced from the Royalty Properties and could increase the cost of operations of the Underlying Properties, which could result in a loss of reserves or revenues to the Trust.
Pursuant to the CAA and state laws concerning the permitting of air emissions, certain new and modified sources of air emissions are subject to air permitting authorizations for construction and operation, and sources of air emissions at the Underlying Properties are no exception to these requirements. In addition to air permitting requirements, certain sources of emissions involved in oil and gas operations are subject to source-specific emission standards pursuant to CAA New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAPs”). For example, on August 16, 2012, the EPA issued a final rule, known as NSPS Subpart OOOO, that established new source performance standards for volatile organic compounds (“VOCs”) and sulfur dioxide, an air toxics standard for major sources of oil and natural gas production, and an air toxics standard for major sources of natural gas transmission and storage. The rule applied to certain oil and natural gas sources that were constructed, modified, or reconstructed after August 23, 2011, and required that all hydraulically fractured or refractured natural gas wells be completed using reduced emission (“green”) completion technology, which significantly reduces VOC emissions. Limiting emissions of VOCs also has the co-benefit of limiting methane, a GHG. In addition, these regulations also include requirements applicable to storage tanks and other equipment in the affected oil and natural gas industry segments. On June 3, 2016, EPA promulgated NSPS Subpart OOOOa, establishing additional standards for the reduction of methane, VOCs, and other emissions from new and existing sources in the oil and gas sector. Among other requirements, these NSPS Subpart OOOOa rules, extended green completion requirements to new hydraulically fractured or refractured oil wells. Furthermore, in December 2023, EPA announced additional final NSPS OOOO program rules, referred to as Subparts OOOOb and OOOOc, which are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective. The rules formally instate methane emissions from new, modified, and reconstructed sources; and will regulate existing sources for the first time under the NSPS Subpart OOOOc program by requiring states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities. Legal , including by states, to the recently finalized NSPS Subparts OOOOb and OOOOc rules have ensued. Further, the EPA under the second Trump Administration issued a Final Rule on December 3, 2025, extending certain OOOOb and OOOOc compliance deadlines. Thus, although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of the VOC and methane emissions regulations for the oil and gas production, transmission, and storage industry segments are uncertain at this time as a result of recent rulemakings and ongoing and expected legal .
Congress and various states, including Texas, have proposed or adopted legislation regulating or requiring disclosure of the chemicals in the hydraulic fracturing fluid that is used in the drilling operation. Texas requires oil and gas operators to disclose the chemicals on the Frac Focus website. Hydraulic fracturing has historically been regulated by state oil and natural gas commissions. The EPA, however, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act (the “SDWA”). The EPA has issued permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuels. Under the guidance, EPA defined the term “diesel” to include five categories of oils, including some such as kerosene, that are not traditionally considered to be diesel.
The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state agency. The CWA also prohibits the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“USACE”). Whether CWA permitting is required depends upon whether and the extent to which “Waters of the United States” (“WOTUS” or "jurisdictional waters") may be impacted by the planned activity—for example, construction of drilling pads, access roads, or pipelines. Rulemaking by EPA and the USACE to define WOTUS has been heavily litigated, resulting in the rule taking effect at times in some states but not others and creating definitions that are more inclusive of certain waters effective in some states and those that are less inclusive effective in other states. EPA and USACE’s WOTUS definition rulemaking published in the Federal Register on January 18, 2023 (the January 2023 Rule) incorporated “relatively permanent” and “significant nexus” standards for determining jurisdiction over adjacent wetlands and additional waters, expanding the types of waters that could be considered WOTUS; however, this WOTUS definition was and eventually amended on August 29, 2023, when EPA and USACE issued a final rule to conform the WOTUS definition to the U.S. Supreme Court’s May 25, 2023 decision in Sackett v. Environmental Protection Agency , which parts of the January 2023 Rule. With the August 2023 rulemaking, EPA and USACE implemented a narrower definition of WOTUS by, for example, removing “interstate wetlands”; redefining “adjacent” to mean “having a continuous surface connection”; and removing the “significant nexus” standard
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from the provisions regarding tributaries, adjacent wetlands, and intrastate lakes and ponds. EPA’s November 17, 2025, proposed rule aims to further conform the WOTUS definition to the Sackett decision by providing additional definitions for “relatively permanent,” “tributary,” and “continuous surface connection,” as well as by introducing additional exclusions and revisions to others, including exclusions for groundwater (i.e., groundwater would not be considered WOTUS) and prior converted cropland, an attempt to clarify the exclusion for ditches, and a broader exclusion for wastewater treatment systems. Comments on the November 2025 proposal were due by January 5, 2026. Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations, such as spill prevention, control, and countermeasure (“SPCC”) planning, may be triggered during development and operation of the Underlying Properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost of development and operation of the Underlying Properties.
SPCC regulations promulgated under the CWA and later amended by the Oil Pollution Act of 1990 impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, must develop, implement, and maintain SPCC Plans. Federal and state regulatory agencies can impose administrative, civil and criminal fines and penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who disposed or arranged for the disposal of a hazardous substance at a site, or transported or arranged for transport of a hazardous substance to a site for disposal. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs of such an action. From time to time, EPA may designate additional materials as hazardous substances under CERCLA, which could result in additional investigation and remediation at current Superfund sites, or reopener of Superfund sites that previously received regulatory closure. For example, EPA issued a final rule that became July 8, 2024, designating as " substances" under CERCLA perfluorooctanoic acid (“PFOA”) and perfluorooctanesulfonic acid (“PFOS”), which have been commonly used in a variety of industrial and consumer products. In the course of operations, the working interest owner and/or the operator of the Underlying Properties may have generated and may generate wastes that may fall within CERCLA’s definition of “ substances.” The operator of the Underlying Properties or the working interest owners may be responsible under CERCLA for all or part of the costs to clean up sites at which such substances have been disposed. Although the Trust is not the operator of any of the Underlying Properties, or the owner of any working interest, its ownership of royalty interests could cause it to be responsible for all or part of such costs to the extent responsibility under CERCLA could be imposed on such parties as “owners.”
The Underlying Properties have produced oil and/or gas for many years and, in connection with that production, managed waste, such as drilling fluids and produced water, that is subject to regulation under environmental laws. Although the Trust has no knowledge of the procedures followed by the operators of the Underlying Properties in this regard, hydrocarbons or other solid wastes (including hazardous or nonhazardous waste) may have been or may be disposed or released on, under, or from the Underlying Properties by the current or previous operators or may have been disposed offsite of the Underlying Properties. Federal, state and local laws and regulations applicable to oil and gas-related wastes and properties have become increasingly more stringent. The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 (“RCRA”) and analogous state laws regulate the management and disposal of solid waste, including hazardous and nonhazardous waste. Although some wastes associated with the exploration and production of oil and natural gas are currently regulated as nonhazardous waste and are exempted from hazardous waste regulation under RCRA, this exemption is subject to being limited or lost, and the loss of this exemption would result in more regulation of these types of waste. Moreover, these wastes and other wastes may be otherwise regulated by the EPA or state agencies. In addition, in the ordinary course of operation of the Underlying Properties, industrial wastes such as paint wastes and waste solvents may be regulated as waste under RCRA or considered substances under CERCLA. to comply with these laws and regulations may result in the assessment of administrative, civil or , the imposition of investigatory, ongoing monitoring, or remedial obligations, and/or the issuance of limiting or some or all of the operations. Under these laws, removal or remediation of current releases of such materials or of previously disposed wastes or property contamination at a drill site or a waste disposal facility could be required by a governmental authority regardless of whether the operators of the Underlying Properties were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken.
The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control (“UIC”) program promulgated under the SDWA and analogous state programs regulate the drilling and operation of salt water disposal and injection wells. EPA directly administers the UIC program in some states and in others administration is delegated to the state. Permits must be obtained before drilling salt water disposal and injection wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater. In addition, because some states have become concerned that the injection or disposal of
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produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering additional regulations regarding the potential seismic impacts of such disposal methods. Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Underlying Properties to dispose of produced water and ultimately increase the cost of operation of the Underlying Properties or delay production schedules. For example, in 2014, the Railroad Commission of Texas (“RRC”) published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, or the permit application or existing operating permit for that well. Furthermore, in response to a number of earthquakes in recent years in the Midland Basin, the RRC announced in September 2021 that it will not issue any new saltwater disposal (“SWD”) well permits in an area known as the Gardendale Seismic Response Area (“SRA”), and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well. In December 2021, the RRC went on to all well activity in deep formations in the Gardendale SRA, effectively 33 disposal well permits. The RRC has since identified two additional SRAs; (the Northern Culberson-Reeves (“NCR”) SRA and the Stanton SRA), and required operators in the NCR and Stanton SRAs to develop and implement seismic response plans, (which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff). In response to additional earthquakes in the area, the RRC all (totaling 23) deep disposal well permits in the NCR SRA and proposed additional daily injection volume for the Stanton SRA. Such restrictions and requirements could limit the Underlying Properties’ oil and gas well exploration and production activities or increase the cost of those activities if wastewater disposal options become limited.
In addition, several cases have in recent years put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. In a statement issued by EPA in April 2019, the Agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, in April 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v. Hawaii Wildlife Fund , holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. In November 2023, EPA issued draft guidance outlining the factors that may be considered when evaluating whether discharges through groundwater may be the “functional equivalent” of a direct discharge and subject to regulation under the CWA National Pollutant Discharge Elimination System permitting program and describing the types of information that should be used in the determination. Comments on the draft guidance were due to the agency by December 27, 2023, and to date EPA has not yet finalized the guidance. If in the future CWA permitting is required for saltwater injection wells as a result of the Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund , the costs of permitting and compliance for injection well operations by the companies that operate the Underlying Properties could increase.
Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds and their habitat, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Bald and Golden Eagle Protection Act, the CWA, and CERCLA.
The United States Fish and Wildlife Service (“USFWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to, species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in some cases, .
The operators of the Underlying Properties are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. In addition to the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the Clean Air Act, and similar state statutes may also require disclosure of information about hazardous materials used, produced or otherwise managed during operation of the Underlying Properties. Some of these laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants.
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The Trustee is unable to predict the total impact of the current and potential regulations upon the operators of the Underlying Properties; the effect that noncompliance with existing environmental laws, rules and regulations; compliance with new legislation or regulation, or enforcement policies thereunder; or claims for property or environmental damage, or for personal injury or death, resulting from operations on the Underlying Properties could have on the Trust or Trust distributions. Even if the Trust were not directly liable for costs or expenses related to these matters, it is possible that the operators of the Underlying Properties could face operational delays, increases in the operating costs to comply with climate change or any other existing or new environmental legislation or regulation, decreases in the completion of new oil and natural gas wells, or an enforcement action or a private party action that could result in wells being plugged and abandoned earlier in their productive lives, resulting in a loss of reserves and revenues to the Trust each of which could reduce net proceeds payable to the Trust and Trust distributions.
Other Regulation
The petroleum industry is also subject to compliance with various other federal, tribal, state, and local regulations and laws, including, but not limited to, occupational safety, resource conservation and equal employment opportunity. The Trustee does not believe that compliance with these laws by the operating parties will have any material adverse effect on Unit holders.
Item 3. Legal Pro ceedings
SoftVest Petition
On December 26, 2025, SoftVest, L.P. (“SoftVest”), a Unit holder of the Trust, filed an Original Petition for Modification of Trust (the “Petition”) in the District Court of Tarrant County, Texas (Cause No. 96-373245-25) seeking judicial modification of the Trust’s Indenture. In the Petition, SoftVest seeks to (1) amend Section 8.03 of the Indenture to eliminate the requirement that certain amendments require approval by 75% of the outstanding Units of the Trust, and (2) delete Section 10.01 of the Indenture that sets forth certain prohibited amendments and replace Article X of the Indenture with a provision permitting amendment of any provision of the Indenture by a vote of Unit holders in accordance with Article VIII (which, as amended, would permit amendment by a majority in interest of Unit holders constituting a quorum at a meeting of Unit holders where a quorum is present). A hearing on the Petition is scheduled for Friday, May 8, 2026 at 10:30 a.m.
Blackbeard Settlement
On August 19, 2025, the Trustee entered into a settlement agreement and release (the “Settlement Agreement”) in connection with its lawsuit against Blackbeard, as operator of the properties in the Waddell Ranch, in Crane County, Texas, in which the Trust holds a 75% net overriding royalty. Pursuant to the lawsuit, the Trustee had sought to recover more than $9 million in damages it alleged resulted from Blackbeard’s failure to properly calculate and pay royalties due and owing to the Trust.
Pursuant to the Settlement Agreement, Blackbeard agreed to pay the Trust $9,000,000, of which $4,500,000 was paid to the Trust on September 18, 2025, and the remainder of which will be paid in four equal installments of $1,125,000 quarterly during the 2026 calendar year.
Additionally, the Settlement Agreement established the overhead rate that may be charged to the Trust and permits Blackbeard to pass through third-party charges for salt water disposal, gathering and transportation, and charge technical labor on reservoir engineers using an agreed allocation methodology against the net overriding royalty. The parties also agreed that the Trust would not make future claims for lost volumes in the case of ordinary line loss (as defined by third party purchase agreements with purchasers). The Trust will have the option to conduct annual site audits, at its expense. The Settlement Agreement also set forth agreed reporting that Blackbeard will provide the Trustee going forward.
Except as described above, there are no material pending legal proceedings to which the Trust is a party or of which any of its property is the subject.
Item 4. Mine Safe ty Disclosures
This Item is not applicable to the Trust.
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