NYSE: SBR

In order to avoid uncertainty under Louisiana law as to the legality of the Trustee’s holding record title to the Royalty Properties located in that state, title to such properties has historically been held by a separate trust formed under the laws of Louisiana, the sole beneficiary of which was the Trust. Sabine Louisiana Royalty Trust was a passive entity, with the trustee thereof, Hibernia National Bank in New Orleans, having only such powers as were necessary for the collection of and distribution of revenues from and the protection of the Royalty Properties located in Louisiana and the payment of liabilities of Sabine Louisiana Royalty Trust. Argent now serves as Trustee of the Sabine Louisiana Royalty Trust. A separate trust also was established to hold record title to the Royalty Properties located in Florida. Legislation was adopted in Florida in 1992 that eliminated the provision of Florida law that prohibited the Trustee from holding record title to the Royalty Properties located in that state. In November 1993, record title to the Royalty Properties held by the trustee of Sabine Florida Land Trust was transferred to the Trustee. In discussing the Trust, this report disregards the technical ownership formalities described in this paragraph, which have no effect on the tax or accounting treatment of the Royalty Properties, since the observance thereof would significantly complicate the information presented herein without any corresponding benefit to Unit holders.

Certificates evidencing units of beneficial interest (the “Units”) in the Trust were mailed on December 31, 1982, to the shareholders of Sabine Corporation of record on December 23, 1982, on the basis of one Unit for each outstanding share of common stock of Sabine Corporation. The Units are listed and traded on the New York Stock Exchange under the symbol “SBR.”

In May 1988, Sabine Corporation was acquired by Pacific Enterprises. Through a series of mergers, Sabine Corporation was merged into Pacific Enterprises Oil Company (USA) (“Pacific (USA)”), which in turn was merged and consolidated into Sempra Energy, effective January 1, 1993. As of August 1, 2006, Sempra Energy sold its various interests and rights to Providence Energy Corporation (“Providence”). Providence in turn transferred its interests and rights to RJ Holdings, Inc. (“RJ Holdings”) as of June 1, 2021. These transactions had no effect on the Units. RJ Holdings, Inc., as successor to Sabine Corporation, has assumed by operation of law all of Sabine Corporation’s rights and obligations with respect to the Trust. References herein to RJ Holdings, Inc. shall be deemed to include Sabine Corporation where appropriate.

In connection with the transfer of the Royalty Properties to the Trust upon its formation, Sabine Corporation had reserved to itself all executive rights, including rights to execute leases and to receive bonuses and delay rentals. Through a series of mergers, Sabine Corporation was merged into Pacific Enterprises Oil Company (USA) (“Pacific (USA)”), a California corporation which in turn was merged and consolidated into Sempra Energy, effective January 1, 1993. In January 1993, Pacific (USA) completed the sale of substantially all of Pacific (USA)’s producing oil and gas assets to Hunt Oil Company. The sale did not include the executive rights relating to the Royalty Properties, and ownership of such rights by Pacific (USA) (now PEC Minerals, LP (“PEC”)) was not affected by the sale. The Trustee currently reviews all leases executed on the Trust’s behalf.

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On January 9, 2014, Bank of America, N.A. (as successor to InterFirst Bank Dallas, N.A.) gave notice to Unit holders that it was resigning as the Trustee subject to certain conditions including the appointment of Southwest Bank as trustee of the Trust. At a special meeting of Trust Unit holders, the Unit holders approved the appointment of Southwest Bank as successor trustee of the Trust, once Bank of America, N.A.’s resignation took effect. The effective date of Bank of America, N.A.’s resignation and the effective date of Southwest Bank’s appointment as successor trustee was May 30, 2014.

Effective October 19, 2017, Simmons First National Corporation (“SFNC”) completed its acquisition of First Texas BHC, Inc., the parent company of Southwest Bank. SFNC is the parent of Simmons Bank. SFNC merged Southwest Bank with Simmons Bank effective February 20, 2018.

On November 4, 2021, Simmons Bank, as Trustee, announced that it had entered into an agreement with Argent, pursuant to which Simmons Bank would resign as trustee of the Trust and would nominate Argent as successor trustee of the Trust. At a special meeting of Trust Unit holders, the Unit holders approved the appointment of Argent as successor trustee of the Trust. Simmons Bank’s resignation as trustee, and Argent’s appointment as successor trustee, became effective December 30, 2022.

The defined term “Trustee” as used herein shall refer to Bank of America, N.A. for periods prior to May 30, 2014, shall refer to Southwest Bank for periods from May 30, 2014 through February 19, 2018, shall refer to Simmons Bank for periods on and after February 20, 2018 through December 29, 2022, and shall refer to Argent for periods on and after December 30, 2022.

The following summaries of certain provisions of the Trust Agreement are qualified in their entirety by reference to the Trust Agreement itself, which is an exhibit to the Form 10-K and available upon request from the Trustee. The definitions, formulas, accounting procedures and other terms governing the Trust are complex and extensive and no attempt has been made below to describe all such provisions. Capitalized terms not otherwise defined herein are used with the meanings ascribed to them in the Trust Agreement.

Assets of the Trust

The Royalty Properties are the only assets of the Trust, other than cash being held for the payment of expenses and liabilities and for distribution to the Unit holders. Pending such payment of expenses and distribution to Unit holders, cash may be invested by the Trustee only in certificates of deposit, United States government securities, repurchase agreements secured by United States government securities or other interest bearing accounts in FDIC-insured state or national banks (including the Trustee) so long as the entire amount in such accounts is at all times fully insured by the FDIC. See “Duties and Limited Powers of Trustee” below.

Liabilities of the Trust

Because of the passive nature of the Trust’s assets and the restrictions on the power of the Trustee to incur obligations, it is anticipated that the only liabilities the Trust will incur are those for routine administrative expenses, such as trustee’s fees, accounting, engineering, legal and other professional fees. The total general and administrative expenses for the Trust for 2025 were $4,090,067 of which, pursuant to the terms of the Trust Agreement, $556,852 was paid to Argent Trust Company as Trustee, and $1,670,553 was paid to Argent Trust Company, as escrow agent, respectively.

Duties and Limited Powers of Trustee

The duties of the Trustee are specified in the Trust Agreement and by the laws of the State of Texas. The basic function of the Trustee is to collect income from the Trust properties, to pay out of the Trust’s income and assets all expenses, charges and obligations, and to pay available income to Unit holders. Since PEC has retained the executive rights with respect to the minerals included in the Royalty Properties and the right to receive any future bonus payments or delay rentals resulting from leases with respect to such minerals, the Trustee is not required to make any investment or operating decision with respect to the Royalty Properties.

The Trust has no employees. Administrative functions of the Trust are performed by the Trustee.

The Trustee has the discretion to establish a cash reserve for the payment of any liability that is contingent or uncertain in amount or that otherwise is not currently due and payable. The Trustee has the power to borrow funds required to pay liabilities of the Trust as they become due and pledge or otherwise encumber the Trust’s properties if it determines that the cash on hand is insufficient to pay such liabilities. Borrowings must be repaid in full before any further distributions are made to Unit holders. All distributable income of the Trust is distributed on a monthly basis. The Trustee is required to invest any cash being held by it for distribution on the next Distribution Date or as a reserve for liabilities in certificates of deposit, United States government securities, repurchase agreements secured by United States government securities or other interest bearing accounts in FDIC-insured state or national banks (including the Trustee) so long as the entire amount in such accounts is at all times fully insured by the FDIC. The Trustee furnishes Unit holders with periodic reports. See “Item 1 — Description of Units — Reports to Unit Holders.”

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The Trust Agreement grants the Trustee only such rights and powers as are necessary to achieve the purposes of the Trust. The Trust Agreement prohibits the Trustee from engaging in any business, commercial or, with certain exceptions, investment activity of any kind and from using any portion of the assets of the Trust to acquire any oil and gas lease, royalty or other mineral interest other than the Royalty Properties. The Trustee may sell Trust properties only as authorized by a vote of the Unit holders, or when necessary to provide for the payment of specific liabilities of the Trust then due or upon termination of the Trust. Pledges or other encumbrances to secure borrowings are permitted without the authorization of Unit holders if the Trustee determines such action is advisable. Any sale of Trust properties must be for cash unless otherwise authorized by the Unit holders or unless the properties are being sold to provide for the payment of specific liabilities of the Trust then due, and the Trustee is obligated to distribute the available net proceeds of any such sale to the Unit holders.

Liabilities of Trustee

The Trustee is to be indemnified out of the assets of the Trust for any liability, expense, claim, damage or other loss incurred by it in the performance of its duties unless such loss results from its negligence, bad faith or fraud or from its expenses in carrying out such duties exceeding the compensation and reimbursement it is entitled to under the Trust Agreement. The Trustee can be reimbursed out of the Trust assets for any liability imposed upon the Trustee for its failure to ensure that the Trust’s liabilities are satisfiable only out of Trust assets. In no event will the Trustee be deemed to have acted negligently, fraudulently or in bad faith if it takes or suffers action in good faith in reliance upon and in accordance with the advice of parties considered to be qualified as experts on the matters submitted to them. The Trustee is not entitled to indemnification from Unit holders except in certain limited circumstances related to the replacement of mutilated, destroyed, lost or stolen certificates. See “Item 1 — Description of Units — Liability of Unit Holders.”

Duration of Trust

The Trust is irrevocable and neither PEC nor RJ Holdings has the power to terminate the Trust or, except with respect to certain corrective amendments, to alter or amend the terms of the Trust Agreement. The Trust will exist until it is terminated by (i) two successive fiscal years in which the Trust’s gross revenues from the Royalty Properties are less than $2,000,000 per year, (ii) a vote of Unit holders as described below under “Voting Rights of Unit Holders” or (iii) operation of provisions of the Trust Agreement intended to permit compliance by the Trust with the “rule against perpetuities.”

Upon the termination of the Trust, the Trustee will continue to act in such capacity until all the assets of the Trust are distributed. The Trustee will sell all Trust properties for cash (unless the Unit holders authorize the sale for a specified non-cash consideration, in which event the Trustee may, but is not obligated to, consummate such non-cash sale) in one or more sales and, after satisfying all existing liabilities and establishing adequate reserves for the payment of contingent liabilities, will distribute all available proceeds to the Unit holders.

Voting Rights of Unit Holders

Although Unit holders possess certain voting rights, their voting rights are not comparable to those of shareholders of a corporation. For example, there is no requirement for annual meetings of Unit holders or for annual or other periodic re-election of the Trustee.

The Trust Agreement may be amended by the affirmative vote of a majority of the outstanding Units at any duly called meeting of Unit holders. However, no such amendment may alter the relative rights of Unit holders unless approved by the affirmative vote of 100 percent of the Unit holders and by the Trustee. In addition, certain special voting requirements can be amended only if such amendment is approved by the holders of at least 80 percent of the outstanding Units and by the Trustee.

Removal of the Trustee requires the affirmative vote of the holders of a majority of the Units represented at a duly called meeting of Unit holders. In the event of a vacancy in the position of Trustee or if the Trustee has given notice of its intention to resign, a successor trustee of the Trust may be appointed by similar voting approval of the Unit holders.

The sale of all or any part of the assets of the Trust must be authorized by the affirmative vote of the holders of a majority of the outstanding Units. However, the Trustee may, without a vote of the Unit holders, sell all or any part of the Trust assets upon termination of the Trust or otherwise if necessary to provide for the payment of specific liabilities of the Trust then due. The Trust can be terminated by the Unit holders only if the termination is approved by the holders of a majority of the outstanding Units.

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Meetings of Unit holders may be called by the Trustee at any time at its discretion and must be called by the Trustee at the written request of holders of not less than 10 percent of the then outstanding Units. The presence of a majority of the outstanding Units is necessary to constitute a quorum and Unit holders may vote in person or by proxy.

Notice of any meeting of Unit holders must be given not more than 60 nor less than 20 days prior to the date of such meeting. The notice must state the purposes of the meeting and no other matter may be presented or acted upon at the meeting.

DESCRIPTION OF UNITS

Each Unit represents an equal undivided share of beneficial interest in the Trust and is evidenced by a transferable certificate issued by the Trustee. Each Unit entitles its holder to the same rights as the holder of any other Unit, and the Trust has no other authorized or outstanding class of equity security. At February 27, 2026, there were 14,579,345 Units outstanding.

The Trust may not issue additional Units unless such issuance is approved by the holders of at least 80 percent of the outstanding Units and by the Trustee. Under limited circumstances, Units may be redeemed by the Trust and canceled. See “Possible Divestiture of Units” below.

Distributions of Distributable Income

The identity of Unit holders entitled to receive distributions of Trust distributable income and the amounts thereof are determined as of each Monthly Record Date. Unit holders of record as of the Monthly Record Date (the 15th day of each calendar month except in limited circumstances) are entitled to have distributed to them the calculated Monthly Income Amount for the related Monthly Period no later than 10 business days after the Monthly Record Date. The Monthly Income Amount is the excess of (i) revenues from the Trust properties plus any decrease in cash reserves previously established for contingent liabilities and any other cash receipts of the Trust over (ii) the expenses and payments of liabilities of the Trust plus any increase in cash reserves for contingent liabilities.

Transfer

Units are transferable on the records of the Trustee upon surrender of any certificate in proper form for transfer (or in compliance with the Trustee’s procedures for uncertificated Units) and compliance with such reasonable regulations as the Trustee may prescribe. No service charge is made to the transferor or transferee for any transfer of a Unit, but the Trustee may require payment of a sum sufficient to cover any tax or governmental charge that may be imposed in relation to such transfer. Until any such transfer, the Trustee may conclusively treat the holder of a Unit shown by its records as the owner of that Unit for all purposes. Any such transfer of a Unit will, as to the Trustee, vest in the transferee all rights of the transferor at the date of transfer, except that the transfer of a Unit after the Monthly Record Date for a distribution will not transfer the right of the transferor to such distribution.

The transfer of Units by gift and the transfer of Units held by a decedent’s estate, and distributions from the Trust in respect thereof, may be restricted under applicable state law.

Equiniti Trust Company, LLC serves as the transfer agent and registrar for the Units.

Reports to Unit Holders

As promptly as practicable following the end of each fiscal year, the Trustee mails to each person who was a Unit holder on any Monthly Record Date during such fiscal year, a report showing in reasonable detail on a cash basis the receipts and disbursements and income and expenses of the Trust for federal and state tax purposes for each Monthly Period during such fiscal year and containing sufficient information to enable Unit holders to make all calculations necessary for federal and state tax purposes. As promptly as practicable following the end of each of the first three fiscal quarters of each year, the Trustee mails a report for such fiscal quarter showing in reasonable detail on a cash basis the assets and liabilities, receipts and disbursements, and income and expenses of the Trust for such fiscal quarter to Unit holders of record on the last Monthly Record Date immediately preceding the mailing thereof. Within 120 days following the end of each fiscal year, or such shorter period as may be required by the New York Stock Exchange, the Trustee mails to Unit holders of record on the last Monthly Record Date immediately preceding the mailing thereof, an annual report containing audited financial statements of the Trust and an audited statement of fees and expenses paid by the Trust to the Trustee and escrow agent. See “Federal Taxation” below.

Each Unit holder and his or her duly authorized agent has the right, during reasonable business hours at his or her own expense, to examine and make audits of the Trust and the records of the Trustee, including lists of Unit holders, for any proper purpose in reference thereto.

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Widely Held Fixed Investment Trust Reporting Information

Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, referred to herein collectively as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. Argent, EIN 62-1437218, 3838 Oak Lawn Avenue, Suite 1720, Dallas, Texas, 75219, telephone number 1-855-588-7839, email address trustee@sbr-sabine.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.sbr-sabine.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unit holders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units, including the issuance of Internal Revenue Service (the “Service”) Forms 1099 and certain written tax statements. Unit holders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.

Liability of Unit Holders

The Trustee, in engaging in any activity or transaction that results or could result in any kind of liability, will be fully liable to Unit Holders if the Trustee fails to take reasonable steps necessary to ensure that such liability is satisfiable only out of the Trust assets (even if the assets are inadequate to satisfy the liability) and in no event out of amounts distributed to, or other assets owned by, Unit holders. However, the Trust might be held to constitute a “joint stock company” under Texas law, which is unsettled on this point, and therefore a Unit holder 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 both the Trust and the Trustee are not adequate to satisfy such liability. In view of the substantial value and passive nature of the Trust assets, the restrictions on the power of the Trustee to incur liabilities and the required financial net worth of any trustee of the Trust, the imposition of any liability on a Unit holder is believed to be extremely unlikely.

Possible Divestiture of Units

The Trust Agreement imposes no restrictions based on nationality or other status of the persons or entities which are eligible to hold Units. However, the Trust Agreement provides that if at any time the Trust or the Trustee is named a party in any judicial or administrative proceeding seeking the cancellation or forfeiture of any property in which the Trust has an interest because of the nationality, or any other status, of any one or more Unit holders, the following procedure will be applicable:

1. The Trustee will give written notice to each holder whose nationality or other status is an issue in the proceeding of the existence of such controversy. The notice will contain a reasonable summary of such controversy and will constitute a demand to each such holder that he or she dispose of his or her Units within 30 days to a party not of the nationality or other status at issue in the proceeding described in the notice.

2. If any holder fails to dispose of his or her Units in accordance with such notice, the Trustee shall have the preemptive right to redeem and shall redeem, at any time during the 90-day period following the termination of the 30-day period specified in the notice, any Unit not so transferred for a cash price equal to the closing price of the Units on the stock exchange on which the Units are then listed or, in the absence of any such listing, the mean between the closing bid and asked prices for the Units in the over-the-counter market, as of the last business day prior to the expiration of the 30-day period stated in the notice.

3. The Trustee shall cancel any Unit acquired in accordance with the foregoing procedures.

4. The Trustee may, in its sole discretion, cause the Trust to borrow any amount required to redeem Units.

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FEDERAL TAXATION

The tax consequences to a Unit holder of the ownership and sale of units will depend in part on the Unit holder’s tax circumstances. Each Unit holder should therefore consult the Unit holder’s tax advisor about the federal, state and local tax consequences to the Unit holder of the ownership of units.

In May 1983, the Service ruled that the Trust is classified as a grantor trust for federal income tax purposes and not as an association taxable as a corporation. Accordingly, the income and deductions of the Trust are reportable directly by Unit holders for federal income tax purposes. The Service also ruled that Unit holders would be entitled to deduct cost depletion with respect to their investment in the Trust and that the transfer of a Unit in the Trust would be considered to be a transfer of a proportionate part of the Royalty Properties held by the Trust.

Transferees of Units transferred after October 11, 1990, may be entitled to a percentage depletion deduction attributable to such Units, if the percentage depletion deduction exceeds cost depletion. Unlike cost depletion, percentage depletion is not limited to a Unit holder’s depletable tax basis in the Units. Rather, a Unit holder is entitled to a percentage depletion deduction as long as the applicable Royalty Properties generate gross income. Unit holders should compute both percentage depletion and cost depletion from each property and claim the larger amount as a deduction on their income tax returns.

If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and if the adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Internal Revenue Code (the “Code”), the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of Section 1254 property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The Service could take the position that a Unit holder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit.

Unit holders must maintain records of their adjusted basis in their Trust Units (generally their cost less prior depletion deductions), make adjustments for depletion deductions to such basis, and use the adjusted basis for the computation of gain or loss on the disposition of the Trust Units.

In order to facilitate the creation of the Trust and to avoid the administrative expense and inconvenience of daily reporting to Unit holders by the Trustee, the conveyances by Sabine Corporation of the Royalty Properties located in five of the six states (Florida, Mississippi, New Mexico, Oklahoma, and Texas) provided for the execution of an escrow agreement by Sabine Corporation and InterFirst (the initial trustee of the Trust), in its capacities as trustee of the Trust and as escrow agent. The conveyances by Sabine Corporation of the Royalty Properties located in Louisiana provided for the execution of a substantially identical escrow agreement by Sabine Corporation and Hibernia National Bank in New Orleans, in the capacities of escrow agent and of trustee of Sabine Louisiana Royalty Trust. The Trust now only has one escrow agent, which is the Trustee, and a single escrow agreement.

Pursuant to the terms of the escrow agreement and the conveyances of the Royalty Properties, the proceeds of production from the Royalty Properties for each calendar month, and interest thereon, are collected by the escrow agent and are paid to and received by the Trust only on the next Monthly Record Date. The escrow agent has agreed to endeavor to assure that it incurs and pays expenses and fees for each calendar month only on the next Monthly Record Date. The Trust Agreement also provides that the Trustee is to endeavor to assure that income of the Trust will be accrued and received and expenses of the Trust will be incurred and paid only on each Monthly Record Date.

Assuming that the escrow arrangement is recognized for federal income tax purposes and that the Trustee, as escrow agent, is able to control the timing of income and expenses, as stated above, cash and accrual basis Unit holders should be treated as realizing income only on each Monthly Record Date. The Trustee, as escrow agent, may not be able to cause third party expenses to be incurred on each Monthly Record Date in all instances. Cash basis Unit holders, however, should be treated as having paid all expenses and fees only when such expenses and fees are actually paid by the Trustee. Even if the escrow arrangement is recognized for federal income tax purposes, however, accrual basis Unit holders might be considered to have accrued expenses when such expenses are incurred rather than on each Monthly Record Date when paid.

No ruling was requested from the Service with respect to the effect of the escrow arrangements when established. Due to the absence of direct authority and the factual nature of the characterization of the relationship among the escrow agents, PEC and the Trust, no opinion was expressed by legal counsel with respect to the tax consequences of the escrow arrangements. If the escrow arrangement is recognized, the income from the Royalty Properties for a calendar month and interest income thereon will be taxed to the holder of the Unit on the next Monthly Record Date without regard to the ownership of the Unit prior to that date. The Trustee is treating the escrow arrangement as effective for tax purposes and furnishes tax information to Unit holders on that basis.

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The Service might take the position that the escrow arrangement should be ignored for federal tax purposes. In such case, the Trustee could be required to report the proceeds from production and interest income thereon to the Unit holders on a daily basis, in accordance with their method of accounting, as the proceeds from production and interest thereon were received or accrued by the escrow agent. Such reporting could impact who is taxed on the production and interest income and result in a substantial increase in the administrative expenses of the Trust. In the event of a transfer of a Unit, the income and the depletion deduction attributable to the Royalty Properties for the period up to the date of transfer would be allocated to the transferor, and the income and depletion deduction attributable to the Royalty Properties on and after the date of transfer would be allocated to the transferee. Such allocation would be required even though the transferee was the holder of the Unit on the next Monthly Record Date and, therefore, would be entitled to the monthly income distribution. Thus, if the escrow arrangement is not recognized, a mismatching of the monthly income distribution and the Unit holder’s taxable income and deductions could occur between a transferor and a transferee upon the transfer of a Unit.

Unit holders of record on each Monthly Record Date are entitled to receive monthly distributions. See “Description of Units — Distributions of Distributable Income” above. The terms of the escrow agreement and the Trust Agreement, as described above, seek to assure that taxable income attributable to such distributions will be reported by the Unit holder who receives such distributions, assuming that such holder is the holder of record on the Monthly Record Date. In certain circumstances, however, a Unit holder may be required to report taxable income attributable to their Units but the Unit holder will not receive the distribution attributable to such income. For example, if the Trustee establishes a reserve or borrows money to satisfy debts and liabilities of the Trust, income used to establish such reserve or to repay such loan will be reported by the Unit holder, even though such income is not distributed to the Unit holder.

Interest and royalty income attributable to ownership of Units and any gain on the sale thereof are considered portfolio income, and not income from a “passive activity,” to the extent a Unit holder acquires and holds Units as an investment and not in the ordinary course of a trade or business. Therefore, interest and royalty income attributable to ownership of Units generally may not be offset by losses from any passive activities.

As a result of the 2017 Tax Cuts and Jobs Act (the “TCJA”), for tax years beginning after December 31, 2017, and before January 1, 2026, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Under the TCJA, for such tax years, personal exemptions and deductions for miscellaneous itemized deductions are not allowed. The U.S. federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and capital gains.

Individuals may incur expenses in connection with the acquisition or maintenance of Trust Units. For tax years beginning before January 1, 2018, and after December 31, 2025, these expenses, which are different from a Unit holder’s share of the Trust’s administrative expenses discussed above, may be deductible as “miscellaneous itemized deductions” only to the extent that such expenses exceed 2% of the individual’s adjusted gross income. Under the TCJA, for tax years beginning after December 31, 2017, and before January 1, 2026, miscellaneous itemized deductions are not allowed.

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law. The OBBBA includes significant federal income tax provisions, such as the permanent extension of the income tax rates set by the TCJA, the continued suspension of miscellaneous itemized deductions and the restoration of favorable tax treatment for certain business provisions. The legislation has multiple effective dates, with certain provisions effective in 2025 and others implemented through 2027. Each Unit holder should consult their own tax advisor regarding the potential tax consequences of the OBBBA and its impact on such person’s ownership of Trust Units.

Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts. For these purposes, investment income generally will include a Unit holder’s allocable share of the Trust’s interest and royalty income plus the gain recognized from a sale of Trust Units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as “FATCA”), distributions from the Trust to “foreign financial institutions” and certain other “non-financial foreign entities” may be subject to U.S. withholding taxes. Specifically, certain “withholdable payments” (including certain royalties, interest and other gains or income from U.S. sources) made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity complies with certain information reporting, withholding, identification, certification and related requirements imposed by FATCA. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

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The Treasury Department issued guidance providing that the FATCA withholding rules described above generally apply to qualifying payments made after June 30, 2014. Foreign Unit holders are encouraged to consult their own tax advisors regarding the possible implications of these withholding provisions on their investment in Trust Units.

The foregoing summary is not exhaustive and does not purport to be complete. Many other provisions of the federal tax laws may affect individual Unit holders. Unit holders should consult their own tax advisor with respect to all Trust tax compliance matters.

STATE TAX CONSIDERATIONS

The following is intended as a brief summary of certain information regarding state taxes and other state tax matters affecting the trust and the Unit holders. Unit holders should consult the Unit holder’s tax advisor regarding state tax filing and compliance matters.

Texas. Texas does not impose an individual income tax. Therefore, no part of the income produced by the Trust is subject to an individual income tax in Texas. However, Texas imposes a franchise tax at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax statutes. Entities subject to tax generally include trusts and most other types of entities having limited liability protection, unless otherwise exempt. Trusts that receive at least 90% of their federal gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are generally exempt from the Texas franchise tax as “passive entities.” The Trust has been and expects to continue to be exempt from Texas franchise tax as a passive entity. Because the Trust should be exempt from Texas franchise tax at the Trust level as a passive entity, each Unit holder that is a taxable entity under the Texas franchise tax generally will be required to include its share of Trust revenues in its own Texas franchise tax computation. This revenue is sourced to Texas under provisions of the Texas Administrative Code providing that such income is sourced according to the principal place of business of the Trust, which is Texas.

Florida, Louisiana, Mississippi, New Mexico and Oklahoma. Florida does not impose an individual income tax. Florida imposes an income tax on resident and nonresident corporations (except for S corporations not subject to the built-in gains tax or passive investment income tax), which will apply to royalty income allocable to a corporate Unit holder from Royalty Properties located within Florida. Louisiana, Mississippi, New Mexico and Oklahoma each impose an income tax applicable to both resident and nonresident individuals and/or corporations (subject to certain exceptions for S corporations and limited liability companies, depending on their treatment for federal tax purposes), which will apply to royalty income allocable to a Unit holder from Royalty Properties located within these states. The Royalty Properties that are located in such states should be considered economic interests in minerals for state income tax purposes.

Generally, the state income tax due by nonresidents in all of the aforementioned states is computed as a percentage of taxable income attributable to the particular state. By contrast, residents are taxed on their taxable income from all sources, wherever earned. Furthermore, even though state laws vary, taxable income for state purposes is often computed in a manner similar to the computation of taxable income for federal income tax purposes. Some of these states give credit for taxes paid to other states by their residents on income from sources in those other states. In certain of these states, a Unit holder is required to file a state income tax return if income is attributable to the Unit holder even though no tax is owed.

Both New Mexico and Oklahoma impose a withholding tax on payments to nonresidents of oil and gas proceeds derived from royalty interests. To reduce the administrative burden imposed by these rules, the Trustee has opted to allow the payors of oil and gas proceeds to withhold on royalty payments made to the Trust. The Trust files New Mexico tax returns, obtains a refund, and distributes that refund to Unit holders.

Withholding at the Trust level reduces the amount of cash available for distribution to Unit holders. Unit holders who transfer their Units before the New Mexico tax refunds are received by the Trust or after the refunds are received but before the next Monthly Record Date will not receive any portion of the refund. As a result, such Unit holders may incur a double tax — first through the reduced distribution received from the Trust and second by the tax payment made directly to the New Mexico taxing authority with the filing of their New Mexico income tax returns (if applicable). With respect to Oklahoma, the Trust has historically filed Oklahoma tax returns, claimed and received refunds for withholding tax and distributed these refunds to Unit holders. However, beginning in 2018 through 2023, the Trust’s refund claims were denied, as the Oklahoma Tax Commission determined that the Trust does not qualify for an exemption from withholding in Oklahoma. For 2024 and forward, pursuant to guidance from the Oklahoma Tax Commission, the Trustee will include Oklahoma source income and related withholding tax on the Trust’s Oklahoma tax return. The excess withholding tax, if any, is refunded to the Trustee. For 2024, this refund has been obtained and distributed to Unit holders.

Unit holders should consult their tax advisor regarding the possible state tax implications of owning Trust Units.

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REGULATION AND PRICES

Regulation

General

Exploration for and production and sale of oil and gas are extensively regulated at the national, state, tribal, and local levels. Oil and gas development and production activities are subject to federal, tribal, state, and local law, regulations and orders of regulatory bodies pursuant thereto. These laws may govern a wide variety of matters, including allowable rates of production, transportation, marketing, pricing, land use, well construction, water use, prevention of waste, waste disposal, pollution, and protection of human health and safety and the environment. These laws, regulations and orders have in the past, and may again, restrict the rate of oil and gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders.

Laws affecting the oil and gas industry and the distribution of its products are under constant review for amendment or expansion, frequently becoming more stringent and are increasing the regulatory burden over time. Numerous governmental departments and agencies are authorized by statute or other laws to issue, and have issued, rules and regulations binding on the oil and gas industry which are often difficult and costly to comply with and which impose substantial penalties or other liabilities for the failure to comply.

Natural Gas

Prices for the sale of natural gas, like the sale of other commodities, are governed by the marketplace and the provisions of applicable gas sales contracts. The Federal Energy Regulatory Commission (“FERC”), which principally is responsible for regulating interstate transportation and the sale of natural gas, has taken significant steps in the implementation of a policy to restructure the natural gas pipeline industry to promote full competition in the sales of natural gas, so that all natural gas suppliers, including pipelines, can compete equally for sales customers. This policy has been implemented largely through restructuring proceedings and is subject to continuing refinement. The effects of this policy are now presumably fully reflected in the natural gas markets. The current policy of FERC continues to promote increased competition among gas industry participants. Accordingly, various regulations and orders have been proposed and implemented to encourage nondiscriminatory open-access transportation by interstate pipelines and to provide for the unbundling of pipeline services so that such services may also be furnished by non-pipeline suppliers on a competitive basis.

Many other statutes, rules, regulations and orders affect the pricing or transportation of natural gas. Some of the provisions are and will be subject to court or administrative review. Consequently, uncertainty as to the ultimate impact of these regulatory provisions on the prices and production of natural gas from the Royalty Properties is expected to continue for the foreseeable future.

Environmental Regulation

General. Activities on the Royalty Properties are subject to existing stringent and complex federal, tribal, state and local laws (including case law), rules and regulations governing health, safety, environmental quality and pollution control. Absent the occurrence of an extraordinary event, the cost of compliance with existing federal, tribal, state and local laws, rules and regulations regulating health, safety, or the protection of the environment are not expected to have a material adverse effect upon the Trust or Unit holders. Those laws and regulations may impose numerous obligations that are applicable to the operations of the Royalty Properties, including the acquisition of a permit before conducting construction, drilling, production, underground injection or associated operational activities; the reporting of the types and quantities of various substances stored, processed, transported, generated, disposed of, or released in connection with operation of the Royalty Properties; planning and preparedness for spill and emergency response activities; the limitation or prohibition of drilling or other oil and gas activities on certain lands lying within wilderness, wetlands, endangered or threatened species habitat and other sensitive or protected areas; the imposition of substantial liabilities for pollution resulting from operations including waste generation, air emissions, water discharges and current and historical waste disposal practices; the remediation of materials released in the environment; the application of specific health and safety criteria addressing worker protection and public health and safety; and the installation of emission monitoring and/or pollution control equipment. Failure, however, to comply with these laws, rules and regulations may result in the assessment of administrative, civil or criminal fines or penalties; the imposition of investigatory ongoing monitoring, or remedial obligations; and the issuance of injunctions or orders limiting or preventing some or all of the operations. Under certain environmental laws and regulations, the operators of the Royalty 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 drill or production or storage 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 the actions were taken.

Drilling, Production and Well Plugging and Abandonment. The production of oil and natural gas is subject to federal, tribal, state and local laws, regulations, codes, ordinances and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters. All of the jurisdictions in which the Royalty 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 permits for the drilling of wells,

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bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, 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 Royalty Properties, decommissioning and removal of equipment, and the plugging and abandonment of wells. Operation of the Royalty Properties is also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. 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 Royalty Properties, negatively affect the economics of production from these wells, or limit the number of wells or locations can be drilled.

Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, and comparable state laws impose liability, regardless of fault or the legality of the conduct at the time it occurred, on certain classes of persons that own or owned property where release of a “hazardous substance” occurred or 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 generated, transported, disposed or arranged for the transport or disposal of a hazardous substance. CERCLA also authorizes the U.S. Environmental Protection Agency (“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, including the costs of certain health studies. In addition, from time to time, the 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, the EPA issued a final rule that became effective on July 8, 2024, designating as “hazardous substances” under CERCLA perfluorooctanoic acid and perfluorooctanesulfonic acid, 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 Royalty Properties may have generated and may generate wastes that may fall within CERCLA’s definition of “hazardous substances.” The operator of the Royalty 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 Royalty 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.”

Solid and Hazardous Waste. The Royalty 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 Royalty Properties in this regard, hydrocarbons or other solid wastes, including hazardous and nonhazardous wastes, may have been or may be disposed or released on, under, or from the Royalty Properties by the current or previous operators or may have been disposed offsite of the Royalty Properties. Federal, state and local laws and regulations applicable to oil and gas- related wastes and properties have generally become more stringent over time. These laws may require not only removal or remediation of current releases of such materials, but also of previously disposed wastes or property contamination at a drill site, production site or waste disposal facility, regardless of whether the current owners or operators were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time of the release or disposal.

For example, 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 stringent 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 Royalty Properties, industrial wastes such as paint wastes and waste solvents may be regulated as hazardous waste under RCRA or considered hazardous substances under CERCLA.

Disposal Wells

The federal Safe Drinking Water Act (“SDWA”), 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. The 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 mechanical 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 produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering

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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 Royalty Properties to dispose of produced water and ultimately increase the cost of operation of the Royalty 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 requires, 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, suspend or terminate 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 in Texas, 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 suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits. The RRC has since identified two additional SRAs (the Northern Culberson-Reeves (“NCR”) SRA and the Stanton SRA), required operators in the NCR SRA and Stanton SRA to implement seismic response plans, (which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff), expanded both the Gardendale and NCR SRAs in response to additional earthquakes in the area suspended all (totaling 23) deep disposal well permits in the NCR SRA (effective January 12, 2024), and, as recently as May 2024, issued revised Response Plans for the Stanton SRA with proposed additional daily injection volume curtailments. Such restrictions and requirements could limit the Royalty 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 Federal Water Pollution Control Act (the “Clean Water Act” or “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. Following a request for comment issued by the EPA 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, the Agency concluded in April 2019 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, the 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 the EPA has not yet finalized the guidance. If in the future CWA permitting is required for any saltwater injection wells as a result of the Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund, the costs associated with operations of the Royalty Properties could increase.

Threatened and Endangered Species, Migratory Birds and Natural Resources. 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 (“MTBA”), the Bald and Golden Eagle Protection Act, the Clean Water Act, 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 damage 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. Damages, including natural resources damages, and criminal penalties for harm to species, habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, produced water, hazardous substances, sediment or other pollutants or regulated materials may be sought. The first Trump administration promulgated a rule in January 2021 that formalized a December 2017 Department of Interior (“DOI”) interpretation of the MBTA as applying only to the intentional killing of birds and not to the accidental but preventable killing of protected birds that occurs as the result of otherwise lawful activities. However, the rule was relatively short-lived. In October 2021, the DOI under the Biden administration issued a rule to reverse the agency’s position on incidental takes of migratory birds, and permanently revoked and withdrew the underlying December 2017 DOI interpretation, citing a federal district court’s opinion in Natural Resources Defense Council v. U.S. Dep’t of the Interior, 478 F. Supp. 3d, 469 (S.D.N.Y. 2020), that the underlying December 2017 DOI interpretation was in clear conflict with long-standing interpretation of the MBTA, and the Second Circuit’s subsequent dismissal of the appeal of the district court’s decision. The reversal of the Trump administration’s January 2021 rule took effect on December 3, 2021.

Water Discharges. The CWA and analogous state laws impose restrictions and strict controls on the discharge of pollutants and fill material, including sediments from construction and spills and leaks of oil and other substances, into regulated waters, including

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some wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or the relevant state agency, or, in the case of dredge or fill material, the United States Army Corps of Engineers (“USACE”).

Which waters are considered protected under the CWA, also known as “waters of the United States” (“WOTUS” or “jurisdictional waters”), has been in flux the past several years due to recent rulemaking and associated litigation concerning the WOTUS definition 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. The 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 litigated and eventually amended on August 29, 2023, when the 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 invalidated parts of the January 2023 Rule. With the August 2023 rulemaking, the 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 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 is not 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 Royalty Properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost of development and operation of the Royalty 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 WOTUS 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.

Climate Change/Air Emissions. Mitigating climate change has become the subject of an important public policy debate and, in the past, the basis for new legislation proposed by the United States Congress and certain states. Some states have also adopted climate change statutes and regulations. 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 announcing a plan to achieve net-zero emissions from overall federal operations by 2050 and making the U.S. power sector carbon-neutral by 2035. 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 volatility, countries feeling vulnerable are increasingly focusing on enhancing their energy security policies, such as emergency stock oil requirements. 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 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 Royalty 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 GHGs are air pollutants under the Clean Air Act (“CAA”), the EPA issued an “Endangerment Finding” under Section 202(a) of the CAA, concluding GHG pollution threatens the public health and welfare of future generations. Thereafter, the EPA issued GHG monitoring and reporting regulations, that since 2012, have required annual reporting of GHGs by persons operating certain types of industrial operations, including oil and gas production, transmission and storage operations that emit 25,000 metric tons or more of carbon dioxide equivalent per year (the

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“GHG Reporting Rule”). 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 GHG Reporting Rule. The 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 Royalty Properties and may have decreased net revenue to the Trust. However, following the second Trump presidential inauguration, Congress postponed collection of the Waste Emissions Charge until 2034 under the One Big Beautiful Bill Act, which President Trump signed into law on July 4, 2025. And, consistent with that postponement, EPA proposed on September 12, 2025, to suspend 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 endangerment finding on the basis that EPA lacks 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 suspended and if the rescission of the endangerment finding is not upheld in the litigation that promptly ensued, operating costs associated with GHG recordkeeping and reporting will continue to be incurred for the Royalty Properties. If GHG 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 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 Royalty 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 Royalty 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. For example, on August 16, 2012, the EPA issued a final rule that established new source performance standards for volatile organic compounds (“VOCs”) and sulfur dioxide, an air toxics standard for sources of oil and natural gas production, and an air toxics standard for 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 must have been completed using so-called “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, referred to as NSPS Subpart OOOO, apply to storage tanks and other equipment in the affected oil and natural gas industry segments. In June 2016, the EPA issued a suite of new final regulations, referred to as NSPS Subpart OOOOa, designed to limit methane, VOCs and other emissions from new and existing sources in the oil and gas sector. Among other requirements, the NSPS Subpart OOOOa rules extended green completion requirements to newly fractured and re-fractured oil wells. Furthermore, in December 2023, the 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 OOOOb and OOOOc rules impose additional methane and VOC emissions limitations from new, modified, and reconstructed sources and would 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 challenges, 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 VOC and methane emission 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 legal challenges.

In part in response to the Inflation Reduction Act requirement for operators to pay royalties on “all gas that is consumed or lost by venting, flaring, or negligent releases through any equipment during upstream operations,” in April 2024, the Bureau of Land Management (“BLM”) finalized the Waste Prevention, Production Subject to Royalties, and Resource Conservation Rule (also known

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as the “Waste Prevention Rule”), which replaces the BLM’s existing venting and flaring requirements in its 1979 Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases: Royalty or Compensation for Oil and Gas Lost (“NTL -4A”) and includes, among others, requirements for self-certification statements or waste minimization plans, flaring limits, leak detection and repair obligations, and for considering oil and gas “unavoidably lost” and, thus, not subject to royalty payments. Implementation of the Waste Prevention Rule could result in increased compliance costs of operation of Royalty Properties on federal and Indian lands. The Waste Prevention Rule went into effect on June 10, 2024. However, in September of 2024, the U.S. District Court for the District of North Dakota granted a motion for preliminary injunction filed by the plaintiff states of North Dakota, Texas, Montana, Wyoming, and Utah, which prohibits BLM “from enforcing the 2024 [Waste Prevention] Rule against the [plaintiff states] pending the outcome of this litigation.” The litigation is currently being held in abeyance in response to the BLM’s request to do so under the second Trump administration, and the BLM, on December 15, 2025, proposed extending two of the December 10, 2025, deadlines for one year while the agency considers revising the underlying requirements. The outcome of the BLM’s potential revisions to the Waste Prevention Rule and the outcome of the North Dakota litigation could affect the validity and substance of the Waste Prevention Rule in the plaintiff and other states. These newly proposed rules could result in increased compliance costs on Royalty Property operations on federal and American Indian lands.

In addition, spurred by increasing concerns regarding climate change, the oil and gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals. Environmental, social, and governance (“ESG”) goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and shareholders across the industry. While reporting on ESG metrics remains voluntary, access to capital and investors is likely to favor companies with robust ESG programs in place. Furthermore, in March 2024 the SEC adopted rule amendments that require public companies to disclose certain climate-related information in their public filings, including information about a company’s climate-related risks that have materially impacted, or are reasonably likely to have a material impact on, its business strategy, results of operations, or financial condition. 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, on March 27, 2025, the SEC voted to end its defense of these rules.

Hydraulic Fracturing. With respect to hydraulic fracturing, in February 2014, the EPA published a final guidance that broadly defined diesel fuel and which required the issuance of a Class II Underground Injection control permit for hydraulic fracturing treatments using diesel fuel. To the extent diesel fuels are used in hydraulic fracturing activities on properties underlying the Royalty Properties, this guidance will apply, and may cause additional costs and delays in development of the Royalty Properties.

Congress and various states, including Texas, Louisiana, Mississippi, New Mexico and Oklahoma, have proposed or adopted legislation regulating or requiring disclosure of the chemicals in the hydraulic fracturing fluid that is used in oil and gas drilling operations. Texas, New Mexico and Oklahoma, among other states require oil and gas operators to disclose the chemicals on the Frac Focus website.

In addition, on March 20, 2015, the BLM released new regulations governing hydraulic fracturing operations on federal and Indian lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. In December of 2017, the BLM rescinded the 2015 regulations, and environmental organizations and the State of California sued the BLM and the Secretary of the U.S. Department of the Interior over the repeal. In March 2020, the Northern District of California issued a ruling in favor of the BLM, upholding the BLM’s rescission of the 2015 regulations. The case has been administratively closed since November 15, 2021; however, if the regulations are reinstated, or if similar regulations are re-proposed, such regulation of hydraulic fracturing operations may result in additional levels of regulatory complexity with respect to existing state regulations that could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase costs of compliance of Royalty Properties on federal and Indian Lands.

A number of governmental agencies have conducted studies on hydraulic fracturing. For example, in 2016 the EPA published a final report of a four-year study focused on the possible relationship between hydraulic fracturing and drinking water. In its assessment, the EPA concluded that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. The results of these studies or similar governmental reviews could spur initiatives to further regulate oil and gas production activities, which could increase the cost to operate the Royalty Properties and could have an adverse effect on the net proceeds payable to the Trust.

OSHA and Other Laws and Regulations. The operators of the Royalty 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

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about hazardous materials used, produced or otherwise managed during operation of the Royalty Properties. Some of these laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants.

The Trustee cannot predict 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 Royalty Properties could have on the Trust or Unit holders. Even if the Trust were not directly liable for costs or expenses related to these matters, increased costs to achieve compliance with existing or new environmental laws, rules or regulations or to respond to an enforcement action or a private party action could result in wells being plugged and abandoned earlier in their productive lives, resulting in a loss of reserves and revenues to the Trust.

Prices

Oil

The Trust’s average per barrel oil price decreased from $77.04 in 2024 to $64.85 in 2025. In 2024, oil prices remained fairly constant throughout the year, with increases in the spring and summer months followed by decreases during the remainder of the year. In 2025, average oil prices were lower overall compared to the prior year. The Trustee believes that the price of oil was affected by higher oil inventories, along with uncertainty in the economy due to U.S. economic and political conditions.

Natural Gas

Natural gas prices, which once were determined largely by governmental regulations, are now being governed by the marketplace. Substantial competition in the natural gas marketplace continues. In addition, competition with alternative fuels persists. The average price received by the Trust in 2025 on natural gas volumes sold of $2.61 per thousand cubic feet (“Mcf”) represented an increase from the $1.88 per Mcf average price received in 2024, mainly due to lower supply as drilling activity declined following the low prices experienced in 2024, along with periods of stronger seasonal demand during 2025. Although prices remained volatile during the year, these factors resulted in a higher average price compared to 2024.