SBR Sabine Royalty Trust

PART I

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, since Louisiana law now permits an out-of-state company to act in this capacity. 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. As used herein, the term “Royalty Properties” includes the Royalty Properties held directly by the Trust and the Royalty Properties located in Louisiana and Florida that were held indirectly through the Trust’s ownership of 100 percent beneficial interest of Sabine Louisiana Royalty Trust and Sabine Florida Land Trust. 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, a California corporation. Through a series of mergers, Sabine 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. As of August 1, 2006, Sempra sold its various interests and rights to Providence Energy Corporation (“PEC”). PEC in turn transferred their interests and rights to RJ Holdings, Inc. (“RJH”) as of June 1, 2021. This acquisition and the subsequent mergers had no effect on the Units. RJHoldings, Inc. as successor to Sabine, has assumed by operation of law all of Sabine’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 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 Pacific (USA)’s ownership of such rights was not affected by the sale. The Trustee currently reviews all leases executed on the Trust’s behalf for accuracy and viability.

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,

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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 2022 were $3,287,420 of which, pursuant to the terms of the Trust Agreement, $422,011 was paid to Simmons Bank, as Trustee, and $1,266,038 was paid to Simmons Bank as escrow agent.

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 Pacific (USA) 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.”

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

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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 Pacific (USA) has no 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.

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.

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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 28, 2023, 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.

American Stock Transfer and Trust Company 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.

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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.

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, 2911 Turtle Creek Blvd., Ste. 850, 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 IRS 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

As regards the 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 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 Internal Revenue Service (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 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 his or her 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

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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, Pacific (USA) 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.

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 Net 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 his or her 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. For such tax years, 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

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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.

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.

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.

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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 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. Although the Trust may be required to file information returns with taxing authorities in those states and provide copies of such returns to the Unit holders, because the Trust distributes all of its net income to Unit holders, the Trust should not be taxed at the Trust level in any of 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 non-residents 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 and Oklahoma 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 either the New Mexico or Oklahoma 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 New Mexico or Oklahoma taxing authorities with the filing of their New Mexico or Oklahoma income tax returns.

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

Units.

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, well construction, water use, prevention of waste, waste disposal, pollution, and protection of human health 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 increasing the regulatory burden. Numerous governmental departments and

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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 activities on certain lands lying within wilderness, wetlands, endangered or threatened species habitat and other 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 penalties; the imposition of investigatory 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 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.

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 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

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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, 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, on August 26, 2022, EPA announced a proposal to designate as hazardous substances 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 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 CERCLA imposes responsibility 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 or hazardous 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. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory, ongoing monitoring or remedial obligations; and/or the issuance of injunctions limiting or preventing some or all of the operations. 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 or a 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 and hazardous waste. Although some wastes associated with the exploration and production of oil and natural gas 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 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 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 additional regulations regarding 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

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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, in September 2021 the RRC announced 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. And in October 2021 and January 2022, respectively, the RRC identified two additional SRAs: the Northern Culberson- Reeves SRA and the Stanton SRA. Operators in the Northern Culberson-Reeves SRA and Stanton SRAs were required to implement seismic response plans, which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff. Both the Gardendale and Northern Culberson-Reeves SRAs were expanded in December 2022 in response to additional earthquakes in the area. 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 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. On January 14, 2021, EPA issued guidance on the ruling, that emphasized only a subset of discharges to groundwater that ultimately reach waters of the U.S. are considered the “functional equivalent” of a direct discharge, although EPA rescinded that guidance on September 16, 2021. 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 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. 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, hazardous substances or other regulated materials may be sought. The 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

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to the accidental but preventable killing of protected birds that occurs as the result of otherwise lawful activities. However, 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 some wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, an analogous 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”), has been in flux the past several years due to recent rulemaking and associated litigation concerning the WOTUS definition. Most recently, EPA and USACE’s WOTUS definition rulemaking on December 30, 2022, incorporated “relatively permanent” and “significant nexus” standards for determining jurisdiction over adjacent wetlands and additional waters. This WOTUS definition will become effective March 20, 2023. 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 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 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 the basis for new legislation proposed by the United States Congress and certain states. Some states have adopted climate change statutes and regulations, and within the first year of his presidency, President Biden signed an executive order to rejoin 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); preparing, maintaining and publishing national greenhouse gas (“GHG”) reduction targets; and announcing a plan to achieve net-zero emissions from overall federal operations by 2050. The Biden administration has also set ambitious domestic targets for curbing climate change, such as making the U.S. power sector carbon-neutral by 2035. Due to factors such as environmental concerns and increased competition from renewables, the International Energy Agency (“IEA”) estimates that natural gas demand in established markets such as the U.S. and the European Union will begin to deteriorate by the mid-2020s, and oil demand will plateau after 2030. Notwithstanding potential risks related to climate change, the IEA estimates that global energy demand will continue to rise and will not peak until after 2030 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. However, for the first time, the IEA’s World Energy Outlook for 2022 estimated that natural gas demand will plateau by the end of the decade, and oil demand will level off in the mid-2030s and fall slightly by 2050.

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”), 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, EPA issued

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GHG monitoring and reporting regulations. Under those rules, since 2012, annual reporting of GHGs has been required for 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. EPA indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG emission limits. More recently, in August 2022, Congress passed the Inflation Reduction Act, which includes requirements to impose fees beginning in 2025 on methane emissions from oil and gas operations that are required to report their GHG emissions under the EPA’s GHG Reporting Rule.

In addition, on January 19, 2021, the D.C. Circuit vacated former president Trump’s administration’s Affordable Clean Energy rule, which had interpreted the CAA as limiting the scope of the federal government’s authority to establishing only source-specific (or “inside the fence line”) emissions reduction requirements for coal-fired power plants. The decision remanded the rule back to the agency, and left the door open for the EPA under President Biden’s administration to adopt more stringent rules on fossil fuel-fired power plants, as well as other measures to reduce GHG emissions associated with power generation and incentivize low-carbon emitting power generation sources. However, in June 2022, the Supreme Court issued a ruling in West Virginia vs. EPA, 142 S. Ct. 2587 (2022), which held that Congress did not grant EPA authority to regulate emissions from power plants using “outside the fence line” mechanisms. Adoption of rules that either place additional limits on GHG emissions from fossil fuel-fired power plants 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 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. For example, on August 16, 2012, 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 will have the co-benefit of also limiting methane, a GHG. These regulations, referred to as NSPS Subpart OOOO, also apply to storage tanks and other equipment in the affected oil and natural gas industry segments. In June 2016, 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 things, these new rules extend green completion requirements to newly fractured and re-fractured oil wells. Furthermore, EPA has also recently proposed to revise and add to the NSPS OOOO program rules which, if adopted, could have a significant impact on the upstream and midstream oil and gas sectors. The proposed rules would formally instate methane and VOC emissions limitations from new, modified, and reconstructed sources; and would regulate existing sources for the first time under the NSPS OOOO program by requiring states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities. Although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of VOC and methane emissions for the oil and gas production, transmission, and storage industry segments are uncertain at this time as a result of ongoing rulemakings and ongoing and expected legal challenges.

In November 2016, the U.S. Department of Interior Bureau of Land Management (“BLM”) published a final version of its venting and flaring rule, which imposes stricter reporting obligations and limits venting and flaring of natural gas on federal and Indian lands; however, before it could take effect, the majority of the rule was struck down by the District Court of Wyoming on October 8, 2020. This ruling is currently being appealed and, thus, the future of the rule is uncertain.

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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 2022 the U.S. Securities and Exchange Commission (“SEC”) proposed rule amendments that would require public companies to disclose certain climate-related information in their public filings. If adopted, the new requirements would begin to phase-in starting in Fiscal Year 2023 and would begin to apply to filings made in 2024. The comment period for the proposed amendments closed in June 2022, and the final rule has not yet been issued. Ultimately, these initiatives could increase operational costs and make it more difficult for companies, including the companies that operate the Royalty Properties, to secure funding for exploration and production activities.

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. Those requirements may cause additional costs and delays in hydraulic fracturing operations using diesel fuels. To the extent diesel fuels are used in hydraulic fracturing activities on properties underlying the Royalty Properties, this guidance will apply.

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.

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 repealed 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. This ruling is currently being appealed, but the case has been administratively closed since November 15, 2021. The regulations, if reinstated, may result in additional levels of regulation or complexity with respect to existing 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. In addition, in May 2022, the U.S. Government Accountability Office released a study on methane emissions from oil and gas development, which included a recommendation that the BLM consider whether to require gas capture plans, including gas capture targets, from operators on federal lands.

A number of governmental agencies have conducted studies on hydraulic fracturing. For example, in 2016 EPA published a final report of a four-year study focused on the possible relationship between hydraulic fracturing and drinking water. In its assessment, 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.

OSHA and Other Laws and Regulations.    The Royalty Properties and operation thereof 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 Royalty 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 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 damages to property, employees, other persons and the environment 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 increased from $57.95 in 2021 to $90.41 in 2022. The Trustee believes that the war in Ukraine and the resulting sanctions against Russia caused the availability of oil to decrease, which in turn put upward pressure on the price, with the peak price occuring in the summer of 2022. As the year went on, the price of oil did decrease somewhat, but the levels were still above that of the previous year.

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 2022 on natural gas volumes sold of $5.96 per Mcf represented an increase from the $3.20 per Mcf received in 2021, due largely to lower supply because of the war in Ukraine and the resulting sanctions against Russia. Like oil, natural gas prices peaked in the summer of 2022, decreasing somewhat afterwards.

When crude oil and natural gas prices decline, the Trust is affected in two ways. First, distributable income from the Royalty Properties is reduced. Second, exploration and development activity by operators on the Royalty 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.

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 Royalty 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:

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 royalties and 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 Royalty 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 Royalty 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. Projects, which are determined solely by the operator, on the Royalty Properties will affect the quantity of proved reserves and can offset the reduction in proved reserves. If the operators developing the Royalty 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.

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 Royalty Properties will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds therefrom.

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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 Royalty Properties. The market price is not necessarily indicative of the value that the Trust would realize if it sold those Royalty Properties 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.

Terrorism and continued hostilities in Eastern Europe and the Middle East 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 the military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism, continued hostilities in Eastern Europe and the Middle East, and 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 Royalty Properties rely could be a direct target or an indirect casualty of an act of terror.

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 Royalty Properties, directly as intended or through unintended consequences.

Governments around the world are considering actions intended to reduce GHG emissions by decreasing both the supply of and the demand for oil and natural gas products or promote 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 Royalty 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 Royalty Properties or decreased market prices could have a material impact on the distributable income of the Trust.

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 banking 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. If the measures taken to protect against cybersecurity disruptions prove to be insufficient or if proprietary data is otherwise not protected, the Trustee or customers, 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

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to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost, or stolen; result in employee, customer, or third-party information being compromised; or otherwise disrupt business operations. The Trust could incur significant costs to remedy the effects of a major cybersecurity disruption in addition to costs in connection with resulting regulatory actions, litigation, or reputational harm.

Future royalty income may be subject to risks related to the creditworthiness of third parties.

The Trust’s future royalty income may be subject to risks relating to the creditworthiness of the operators of 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.

Unit holders and the Trustee have no influence over the operations on, or future development of, the Royalty Properties.

Neither the Trustee nor the Unit holders can influence or control the operations on, or future development of, the Royalty 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 Royalty Properties are under no obligation to continue operations on the Royalty Properties. Neither the Trustee nor the Unit holders have the right to replace an operator.

The operator developing any Royalty Property may abandon the property, thereby terminating the royalties payable to the Trust.

The operators developing the Royalty 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 Royalty Properties can be sold and the Trust would be terminated.

The Trustee must sell the Royalty Properties if Unit holders approve the sale or vote to terminate the Trust as described under “Item 1 — Description of the Trust — Voting Rights of Unit Holders” above. The Trustee must also sell the Royalty Properties if they fail to generate net revenue for the Trust of at least $2,000,000 per year over any consecutive two-year period. Sale of all of the Royalty Properties will terminate the Trust. The net proceeds of any sale will be distributed to the Unit holders. The sale of the remaining Royalty Properties and the termination of the Trust will be taxable events to the Trust Unit holders. Generally, a Trust Unit holder will realize gain or loss equal to the difference between the amount realized on the sale and termination of the Trust and his adjusted basis in such Units. Gain or loss realized by a Trust 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 loss except to the extent of any depletion recapture amount, which must be treated as ordinary income. Other federal and state tax issues concerning the Trust are discussed under Item 1 and Notes 2 and 9 to the Trust’s financial statements, which are included herein. Each Trust Unit holder should consult his own tax advisor regarding Trust tax compliance matters, including federal and state tax implications concerning the sale of the Royalty Properties and the termination 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 Royalty 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.

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The Trust Agreement and related trust law permit the Trustee and the Trust to take appropriate action against the operators developing the Royalty Properties to compel them to fulfill the terms of the conveyance of the Royalty Properties. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the Unit holders would likely be 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 any of the operators developing the Royalty 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, or GAAP. Although this basis of accounting is permitted for royalty trusts by the U.S. Securities and Exchange Commission, the financial statements of the Trust differ from GAAP financial statements 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 accrued in GAAP financial statements.

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 informally known as the Tax Cuts and Jobs Act (the “TCJA”) was enacted December 22, 2017, and makes significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the effective tax rate on a Trust Unit holder’s allocable share of certain income from the Trust. The TCJA is complex, thus, Trust Unit holders should consult their tax advisor regarding the TCJA and its effect on an investment in Trust Units. In addition, President Biden’s administration has generally proposed repealing fossil fuel tax subsidies, which could impact certain tax benefits available to Trust Unit holders.

Any modification to the U.S. federal income tax laws or interpretations thereof (including administrative guidance relating to the TCJA) may be applied retroactively and could adversely affect our 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 used. Any such changes or interpretations could negatively impact the value of an investment in the Trust Units.

The spread of different variants of the COVID-19, or the novel coronavirus, and the continually changing measures taken to mitigate the impact of single or multiple waves of the COVID-19 pandemic, had and may in the future have an adverse effect on the demand for oil and gas and the business and operations of the operators of the 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 the different variants of the COVID-19 pandemic and measures being taken to mitigate its impact. As past coronavirus outbreaks and government responses escalated and de-escalated regionally and sporadically, the extent of any future impact on domestic

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sales of crude oil and natural gas remains unknown. 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. At this time, the full extent to which COVID-19 will negatively impact the global economy and the oil and gas industry in the future is uncertain, but pandemics or other significant public health events will most likely have a material adverse effect on operators’ business and financial condition which would likely have an adverse effect on Trust distributions.

In the East Texas Basin, active plays include the Travis Peak, Bossier and Haynesville. The Mississippi Salt Basin has not been as active lately, but there is still active production from the Hosston. The Anadarko Basin has seen extensive drilling in the Woodford and Mississippian formations in the STACK, SCOOP and MERGE areas. Additional drilling is taking place in the tight gas sands of western Oklahoma and the Texas panhandle. The Arkoma Basin also has Woodford production. A primary area of focus for the industry has been the Permian Basin. Multiple plays are present with some of the more active being the Spraberry, Bone Spring and Wolfcamp formations.

The following table summarizes the gross/net acreage by basin represented by the Royalty Properties at December 31, 2022.

Title

The conveyances of the Royalty Properties to the Trust covered the royalty and mineral properties located in the six states that were vested in Sabine Corporation on the effective date of the conveyances and that were subject to existing oil, gas and other mineral leases other than properties specifically excluded in the conveyances. Since Sabine Corporation may not have had available to it as a royalty owner information as to whether specific lands in which it owned a royalty interest were subject to an existing lease, minimal amounts of nonproducing royalty properties may also have been conveyed to the Trust. Sabine Corporation did not warrant title to the Royalty Properties either expressly or by implication.

Reserves

The Registrant has obtained from DeGolyer and MacNaughton, independent petroleum engineering consultants, a study of the proved oil and gas reserves attributable as of January 1, 2023 to the Royalty Properties. The following letter report summarizes such reserve study and sets forth information as to the assumptions, qualifications, procedures and other matters relating to such reserve study. Because the only assets of the Trust are the Royalty Properties, the Trustee believes the reserve study provides useful information for Unit holders. There are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production. The reserve data set forth herein, although prepared by independent petroleum engineers in a manner customary in the industry, are estimates only, and actual quantities and values of oil and gas are likely to differ from the estimated amounts set forth herein. In addition, the reserve estimates for the Royalty Properties will be affected by future changes in sales prices for oil and gas produced. See Note 8 of the Notes to Financial Statements in Item 8 hereof for additional unaudited information regarding the proved oil and gas reserves of the Trust. Other than those filed with the SEC, our estimated reserves have not been filed with or included in any reports to any federal agency.

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 attributable to the Trust. 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 Trustee gathers production

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information (which information is net to the Trust’s interests in the Royalty Properties) and provides such information to DeGolyer and MacNaughton, who extrapolates from such information estimates of the reserves attributable to the Royalty Properties based on its expertise in the oil and gas fields where the Royalty 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.

DeGolyer and MacNaughton, the independent petroleum engineering consultants who prepared the reserve study, have provided petroleum consulting services for more than 70 years. Dilhan Ilk, Senior Vice President with DeGolyer and MacNaughton, was the primary engineer responsible for the report. Dr. Ilk’s qualifications are set forth in the Certificate of Qualification attached to the letter report below.

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DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 8, 2023

Argent Trust Company

2911 Turtle Creek Blvd, Suite 850

Dallas, Texas 75219-6291

Ladies and Gentlemen:

Pursuant to the request of Sabine Royalty Trust (the Trust), this report of third party presents an independent evaluation, as of January 1, 2023, of the extent and value of the estimated net proved developed producing oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which the Trust has represented it holds an interest. This evaluation was completed on February 8, 2023. The properties evaluated herein consist of royalties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma, and Texas. Argent Trust Company acts as trustee of the Trust. Argent Trust Company has represented that these properties account for 100 percent of revenues attributed to royalty interest payments received by the Trust as of January 1, 2023. The net proved developed producing reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by the Trust.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2022. Net reserves are defined as that portion of the gross reserves attributable to the interests held by the Trust after deducting all interests held by others.

Values for proved developed producing reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad valorem taxes, and transportation expenses from future gross revenue. Transportation expenses include marketing, processing, and other expenses that are charged to the royalty interests. At the request of the Trust, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a discount rate of 10 percent per year compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Estimates of reserves and revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was obtained on behalf of the Trust from Argent Trust Company and from public sources. Additionally, this information includes data supplied by IHS Markit Inc; Copyright 2023 IHS Markit Inc. In the preparation of this report we have relied, without independent verification, upon information furnished by Argent Trust Company with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

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Definition of Reserves

Petroleum reserves included in this report are classified as proved developed producing. Only proved developed producing reserves have been evaluated for this report. Producing reserves are those developed reserves expected to be recovered from completion intervals that are open and producing at the time of the estimate. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) 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.

(ii) 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.

(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.

(iv) 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:

(A) 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 (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) 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 – 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

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(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.

Undeveloped oil and gas reserves – 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.

(i) 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.

(ii) 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 [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019.” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by the Trust, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved developed producing.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report. Because the Trust is unable to provide actual operating expenses for the properties evaluated (since the Trust’s interests are only royalty interests), typical operating expenses, based on our knowledge of the area and/or field operations, were used to determine the economic limits of production.

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

Data provided by the Trust from wells drilled through October 30, 2022, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through October 2022. Estimated cumulative production, as of January 1, 2023, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C₅₊) and liquefied petroleum gas (LPG), which consists

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primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (Mbbl). In these estimates 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state in which the quantities are located. Gas quantities included in this report are expressed in millions of cubic feet (MMcf).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

The Trust has represented that it holds several thousand individual royalty interests. In view of the small reserves volumes attributable to many of these individual interests, certain of the reserves representing approximately 34 percent of the total net reserves of the properties included herein were summarized by state or area and estimated in the aggregate rather than on a property-by-property basis. Historical records of net production and revenue and our general knowledge of producing characteristics in the areas involved were used in evaluating these grouped properties.

Primary Economic Assumptions

Revenue values in this report were estimated using initial prices, expenses, and costs provided by Argent Trust Company. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:

Oil, Condensate, and NGL Prices

The oil, condensate, and NGL prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Differentials to a West Texas Intermediate oil reference price of $94.14 per barrel were based on royalty receipts received by the Trust, as provided by Argent Trust Company. The prices were held constant thereafter. The volume-weighted average prices attributable to the estimated proved developed producing reserves over the lives of the properties were $91.29 per barrel of oil and condensate and $35.45 per barrel of NGL.

Gas Prices

The gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Differentials to the Henry Hub gas reference price of $6.40 per million Btu were based on royalty receipts received by the Trust, as provided by Argent Trust Company. The prices were held constant thereafter. Btu factors provided by Argent Trust Company were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved developed producing reserves over the lives of the properties was $5.682 per thousand cubic feet of gas.

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Production and Ad Valorem Taxes

Production taxes were calculated using rates provided by Argent Trust Company, including, where appropriate, abatements for enhanced recovery programs. Ad valorem taxes were calculated using rates provided by Argent Trust Company based on recent payments by the Trust.

Operating Expenses, Capital Costs, and Abandonment Costs

The properties evaluated are royalties. Therefore, no operating expenses, capital costs, or abandonment costs are incurred. Because the Trust is unable to provide actual operating expenses for the properties evaluated, typical operating expenses, based on our knowledge of the area and/or field operations, were used to determine the economic limits of production.

Several properties incur additional expenses related to transportation, marketing, processing, and other expenses that are charged to the royalty interests. These expenses are reported as transportation expenses. These expenses were not adjusted for inflation.

In our opinion, the information relating to estimated proved developed producing reserves, estimated future net revenue from proved developed producing reserves, and present worth of estimated future net revenue from proved developed producing reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation S–K of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed producing reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

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The estimated future revenue to be derived from the production and sale of the net proved developed producing reserves, as of January 1, 2023, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2023, estimated reserves.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in the Trust. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of the Trust. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

s DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

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CERTIFICATE of QUALIFICATION

I, Dilhan Ilk, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

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There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development. The preceding reserve data in the letter regarding the study represent estimates only and should not be construed to be exact. The estimated present worth of future net revenue amounts shown by the study should not be construed as the current fair market value of the estimated oil and gas reserves since a market value determination would include many additional factors.

Reserve estimates may be adjusted from time to time as more accurate information on the volume or recoverability of existing reserves becomes available. Actual reserve quantities do not change, however, except through production. The Trust continues to own only the Royalty Properties that were initially transferred to the Trust at the time of its creation and is prohibited by the Trust Agreement from acquiring additional oil and gas interests.

The future net revenue shown by the study has not been reduced for administrative costs and expenses of the Trust in future years. The costs and expenses of the Trust may increase in future years, depending on the amount of income from the Royalty Properties, increases in the Trustee’s fees (including escrow agent fees) and expenses, accounting, engineering, legal and other professional fees, and other factors. It is expected that the costs and expenses of the Trust in 2023 will be approximately $3,600,000.

The present value of future net revenue of the Trust’s proved developed reserves increased from $207,073,331 at January 1, 2022 to $327,149,176 at January 1, 2023. This increase resulted primarily from the commodity prices used in the calculation of such amount, from an average price of $63.57 per barrel of oil, $22.21 per barrel of NGL and $3.224 per Mcf of gas at January 1, 2022 to an average price of $91.29 per barrel of oil, $35.45 per barrel of NGL and $5.682 per Mcf of gas at January 1, 2023.

Subsequent to year end, the price of both oil and gas continued to fluctuate, giving rise to a correlating adjustment of the respective standardized measure of discounted future net cash flows. As of February 13, 2023, NYMEX posted oil prices were approximately $80.14 per barrel, which compared to the average posted price of $94.14 per barrel, used to calculate the worth of future net revenue of the Trust’s proved developed reserves, would result in a decrease in the standardized measure of discounted future net cash flows for oil. As of February 13, 2023, NYMEX posted gas prices were $2.42 per million British thermal units. The use of such price, as compared to the average posted price of $3.91 per million British thermal units, used to calculate future net revenue for the Trust’s proved developed reserves would result in a decrease in the standardized measure of discounted future net cash flows for gas.

The volatile nature of the world energy markets makes it difficult to estimate future prices of oil and gas. The prices obtained for oil and gas depend upon numerous factors, none of which is within the Trustee’s control, including the domestic and foreign supply of oil and gas and the price of foreign imports, market demand, the price and availability of alternative fuels, the availability of pipeline capacity, instability in oil-producing regions and the effect of governmental regulations.