EDGAR 10-K Filing

Company CIK: 710752
Filing Year: 2025
Filename: 710752_10-K_2025_0000950170-25-029052.json

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ITEM 1. BUSINESS
Item 1. Business.
DESCRIPTION OF THE TRUST
Sabine Royalty Trust (the “Trust”) is an express trust formed under the laws of the State of Texas by the Sabine Corporation Royalty Trust Agreement (as amended, the “Trust Agreement”) made and entered into effective as of December 31, 1982, between Sabine Corporation (“Sabine Corporation”), as trustor, and InterFirst Bank Dallas, N.A. (“InterFirst”), as trustee. The current trustee of the Trust is Argent Trust Company, a Tennessee chartered trust company (“Argent”). In accordance with the successor trustee provisions of the Trust Agreement, Argent, as trustee of the Trust (the “Trustee”) is subject to all terms and conditions of the Trust Agreement. The principal office of the Trust (sometimes referred to herein as the “Registrant”) is located at 3838 Oak Lawn Avenue, Suite 1720, Dallas, Texas, 75219. The telephone number of the Trust is 1-855-588-7839.
The Trust maintains an internet website, and as a result, reports such as its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to such reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available at http://www.sbr-sabine.com as soon as reasonably practicable after such information is electronically filed with or furnished to the U.S. Securities and Exchange Commission (“SEC”).
On November 12, 1982, the shareholders of Sabine Corporation approved and authorized Sabine Corporation’s transfer of royalty and mineral interests, including landowner’s royalties, overriding royalty interests, minerals (other than executive rights, bonuses and delay rentals), production payments and any other similar, nonparticipatory interests, in certain producing and proved undeveloped oil and gas properties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma and Texas (the “Royalty Properties”) to the Trust. The conveyances of the Royalty Properties to the Trust were effective with respect to production as of 7:00 a.m. (local time) on January 1, 1983.
In order to avoid uncertainty under Louisiana law as to the legality of the Trustee’s holding record title to the Royalty Properties located in that state, title to such properties has historically been held by a separate trust formed under the laws of Louisiana, the sole beneficiary of which was the Trust. Sabine Louisiana Royalty Trust was a passive entity, with the trustee thereof, Hibernia National Bank in New Orleans, having only such powers as were necessary for the collection of and distribution of revenues from and the protection of the Royalty Properties located in Louisiana and the payment of liabilities of Sabine Louisiana Royalty Trust. Argent now serves as Trustee of the Sabine Louisiana Royalty Trust. A separate trust also was established to hold record title to the Royalty Properties located in Florida. Legislation was adopted in Florida in 1992 that eliminated the provision of Florida law that prohibited the Trustee from holding record title to the Royalty Properties located in that state. In November 1993, record title to the Royalty Properties held by the trustee of Sabine Florida Land Trust was transferred to the Trustee. In discussing the Trust, this report disregards the technical ownership formalities described in this paragraph, which have no effect on the tax or accounting treatment of the Royalty Properties, since the observance thereof would significantly complicate the information presented herein without any corresponding benefit to Unit holders.
Certificates evidencing units of beneficial interest (the “Units”) in the Trust were mailed on December 31, 1982, to the shareholders of Sabine Corporation of record on December 23, 1982, on the basis of one Unit for each outstanding share of common stock of Sabine Corporation. The Units are listed and traded on the New York Stock Exchange under the symbol “SBR.”
In May 1988, Sabine Corporation was acquired by Pacific Enterprises. Through a series of mergers, Sabine Corporation was merged into Pacific Enterprises Oil Company (USA) (“Pacific (USA)”), which in turn was merged and consolidated into Sempra Energy, effective January 1, 1993. As of August 1, 2006, Sempra Energy sold its various interests and rights to Providence Energy Corporation (“Providence”). Providence in turn transferred its interests and rights to RJ Holdings, Inc. (“RJ Holdings”) as of June 1, 2021. These transactions had no effect on the Units. RJ Holdings, Inc., as successor to Sabine Corporation, has assumed by operation of law all of Sabine Corporations’s rights and obligations with respect to the Trust. References herein to RJ Holdings, Inc. shall be deemed to include Sabine Corporation where appropriate.
In connection with the transfer of the Royalty Properties to the Trust upon its formation, Sabine Corporation had reserved to itself all executive rights, including rights to execute leases and to receive bonuses and delay rentals. Through a series of mergers, Sabine Corporation was merged into Pacific Enterprises Oil Company (USA) (“Pacific (USA)”), a California corporation which in turn was merged and consolidated into Sempra Energy, effective January 1, 1993. In January 1993, Pacific (USA) completed the sale of substantially all of Pacific (USA)’s producing oil and gas assets to Hunt Oil Company. The sale did not include the executive rights relating to the Royalty Properties, and ownership of such rights by Pacific (USA) (now PEC Minerals, LP (“PEC”)) was not affected by the sale. The Trustee currently reviews all leases executed on the Trust’s behalf.
On January 9, 2014, Bank of America, N.A. (as successor to InterFirst Bank Dallas, N.A.) gave notice to Unit holders that it was resigning as the Trustee subject to certain conditions including the appointment of Southwest Bank as trustee of the Trust. At a special meeting of Trust Unit holders, the Unit holders approved the appointment of Southwest Bank as successor trustee of the Trust, once Bank of America, N.A.’s resignation took effect. The effective date of Bank of America, N.A.’s resignation and the effective date of Southwest Bank’s appointment as successor trustee was May 30, 2014.
Effective October 19, 2017, Simmons First National Corporation (“SFNC”) completed its acquisition of First Texas BHC, Inc., the parent company of Southwest Bank. SFNC is the parent of Simmons Bank. SFNC merged Southwest Bank with Simmons Bank effective February 20, 2018.
On November 4, 2021, Simmons Bank, as Trustee, announced that it had entered into an agreement with Argent, pursuant to which Simmons Bank would resign as trustee of the Trust and would nominate Argent as successor trustee of the Trust. At a special meeting of Trust Unit holders, the Unit holders approved the appointment of Argent as successor trustee of the Trust. Simmons Bank’s resignation as trustee, and Argent’s appointment as successor trustee, became effective December 30, 2022.
The defined term “Trustee” as used herein shall refer to Bank of America, N.A. for periods prior to May 30, 2014, shall refer to Southwest Bank for periods from May 30, 2014 through February 19, 2018, shall refer to Simmons Bank for periods on and after February 20, 2018 through December 29, 2022, and shall refer to Argent for periods on and after December 30, 2022.
The following summaries of certain provisions of the Trust Agreement are qualified in their entirety by reference to the Trust Agreement itself, which is an exhibit to the Form 10-K and available upon request from the Trustee. The definitions, formulas, accounting procedures and other terms governing the Trust are complex and extensive and no attempt has been made below to describe all such provisions. Capitalized terms not otherwise defined herein are used with the meanings ascribed to them in the Trust Agreement.
Assets of the Trust
The Royalty Properties are the only assets of the Trust, other than cash being held for the payment of expenses and liabilities and for distribution to the Unit holders. Pending such payment of expenses and distribution to Unit holders, cash may be invested by the Trustee only in certificates of deposit, United States government securities, repurchase agreements secured by United States government securities or other interest bearing accounts in FDIC-insured state or national banks (including the Trustee) so long as the entire amount in such accounts is at all times fully insured by the FDIC. See “Duties and Limited Powers of Trustee” below.
Liabilities of the Trust
Because of the passive nature of the Trust’s assets and the restrictions on the power of the Trustee to incur obligations, it is anticipated that the only liabilities the Trust will incur are those for routine administrative expenses, such as trustee’s fees, accounting, engineering, legal and other professional fees. The total general and administrative expenses for the Trust for 2024 were $3,528,402 of which, pursuant to the terms of the Trust Agreement, $478,878, was paid to Argent Trust Company as Trustee, and $1,436,631 was paid to Argent Trust Company, as escrow agent, respectively.
Duties and Limited Powers of Trustee
The duties of the Trustee are specified in the Trust Agreement and by the laws of the State of Texas. The basic function of the Trustee is to collect income from the Trust properties, to pay out of the Trust’s income and assets all expenses, charges and obligations, and to pay available income to Unit holders. Since PEC has retained the executive rights with respect to the minerals included in the Royalty Properties and the right to receive any future bonus payments or delay rentals resulting from leases with respect to such minerals, the Trustee is not required to make any investment or operating decision with respect to the Royalty Properties.
The Trust has no employees. Administrative functions of the Trust are performed by the Trustee.
The Trustee has the discretion to establish a cash reserve for the payment of any liability that is contingent or uncertain in amount or that otherwise is not currently due and payable. The Trustee has the power to borrow funds required to pay liabilities of the Trust as they become due and pledge or otherwise encumber the Trust’s properties if it determines that the cash on hand is insufficient to pay such liabilities. Borrowings must be repaid in full before any further distributions are made to Unit holders. All distributable income of the Trust is distributed on a monthly basis. The Trustee is required to invest any cash being held by it for distribution on the next Distribution Date or as a reserve for liabilities in certificates of deposit, United States government securities, repurchase agreements secured by United States government securities or other interest bearing accounts in FDIC-insured state or national banks (including the Trustee) so long as the entire amount in such accounts is at all times fully insured by the FDIC. The Trustee furnishes Unit holders with periodic reports. See “Item 1 - Description of Units - Reports to Unit Holders.”
The Trust Agreement grants the Trustee only such rights and powers as are necessary to achieve the purposes of the Trust. The Trust Agreement prohibits the Trustee from engaging in any business, commercial or, with certain exceptions, investment activity of any kind and from using any portion of the assets of the Trust to acquire any oil and gas lease, royalty or other mineral interest other than the Royalty Properties. The Trustee may sell Trust properties only as authorized by a vote of the Unit holders, or when necessary to provide for the payment of specific liabilities of the Trust then due or upon termination of the Trust. Pledges or other encumbrances to secure borrowings are permitted without the authorization of Unit holders if the Trustee determines such action is advisable. Any sale of Trust properties must be for cash unless otherwise authorized by the Unit holders or unless the properties are being sold to provide for the payment of specific liabilities of the Trust then due, and the Trustee is obligated to distribute the available net proceeds of any such sale to the Unit holders.
Liabilities of Trustee
The Trustee is to be indemnified out of the assets of the Trust for any liability, expense, claim, damage or other loss incurred by it in the performance of its duties unless such loss results from its negligence, bad faith or fraud or from its expenses in carrying out such duties exceeding the compensation and reimbursement it is entitled to under the Trust Agreement. The Trustee can be reimbursed out of the Trust assets for any liability imposed upon the Trustee for its failure to ensure that the Trust’s liabilities are satisfiable only out of Trust assets. In no event will the Trustee be deemed to have acted negligently, fraudulently or in bad faith if it takes or suffers action in good faith in reliance upon and in accordance with the advice of parties considered to be qualified as experts on the matters submitted to them. The Trustee is not entitled to indemnification from Unit holders except in certain limited circumstances related to the replacement of mutilated, destroyed, lost or stolen certificates. See “Item 1 - Description of Units - Liability of Unit Holders.”
Duration of Trust
The Trust is irrevocable and neither PEC nor RJ Holdings has the power to terminate the Trust or, except with respect to certain corrective amendments, to alter or amend the terms of the Trust Agreement. The Trust will exist until it is terminated by (i) two successive fiscal years in which the Trust’s gross revenues from the Royalty Properties are less than $2,000,000 per year, (ii) a vote of Unit holders as described below under “Voting Rights of Unit Holders” or (iii) operation of provisions of the Trust Agreement intended to permit compliance by the Trust with the “rule against perpetuities.”
Upon the termination of the Trust, the Trustee will continue to act in such capacity until all the assets of the Trust are distributed. The Trustee will sell all Trust properties for cash (unless the Unit holders authorize the sale for a specified non-cash consideration, in which event the Trustee may, but is not obligated to, consummate such non-cash sale) in one or more sales and, after satisfying all existing liabilities and establishing adequate reserves for the payment of contingent liabilities, will distribute all available proceeds to the Unit holders.
Voting Rights of Unit Holders
Although Unit holders possess certain voting rights, their voting rights are not comparable to those of shareholders of a corporation. For example, there is no requirement for annual meetings of Unit holders or for annual or other periodic re-election of the Trustee.
The Trust Agreement may be amended by the affirmative vote of a majority of the outstanding Units at any duly called meeting of Unit holders. However, no such amendment may alter the relative rights of Unit holders unless approved by the affirmative vote of 100 percent of the Unit holders and by the Trustee. In addition, certain special voting requirements can be amended only if such amendment is approved by the holders of at least 80 percent of the outstanding Units and by the Trustee.
Removal of the Trustee requires the affirmative vote of the holders of a majority of the Units represented at a duly called meeting of Unit holders. In the event of a vacancy in the position of Trustee or if the Trustee has given notice of its intention to resign, a successor trustee of the Trust may be appointed by similar voting approval of the Unit holders.
The sale of all or any part of the assets of the Trust must be authorized by the affirmative vote of the holders of a majority of the outstanding Units. However, the Trustee may, without a vote of the Unit holders, sell all or any part of the Trust assets upon termination of the Trust or otherwise if necessary to provide for the payment of specific liabilities of the Trust then due. The Trust can be terminated by the Unit holders only if the termination is approved by the holders of a majority of the outstanding Units.
Meetings of Unit holders may be called by the Trustee at any time at its discretion and must be called by the Trustee at the written request of holders of not less than 10 percent of the then outstanding Units. The presence of a majority of the outstanding Units is necessary to constitute a quorum and Unit holders may vote in person or by proxy.
Notice of any meeting of Unit holders must be given not more than 60 nor less than 20 days prior to the date of such meeting. The notice must state the purposes of the meeting and no other matter may be presented or acted upon at the meeting.
DESCRIPTION OF UNITS
Each Unit represents an equal undivided share of beneficial interest in the Trust and is evidenced by a transferable certificate issued by the Trustee. Each Unit entitles its holder to the same rights as the holder of any other Unit, and the Trust has no other authorized or outstanding class of equity security. At February 27, 2025, there were 14,579,345 Units outstanding.
The Trust may not issue additional Units unless such issuance is approved by the holders of at least 80 percent of the outstanding Units and by the Trustee. Under limited circumstances, Units may be redeemed by the Trust and canceled. See “Possible Divestiture of Units” below.
Distributions of Distributable Income
The identity of Unit holders entitled to receive distributions of Trust distributable income and the amounts thereof are determined as of each Monthly Record Date. Unit holders of record as of the Monthly Record Date (the 15th day of each calendar month except in limited circumstances) are entitled to have distributed to them the calculated Monthly Income Amount for the related Monthly Period no later than 10 business days after the Monthly Record Date. The Monthly Income Amount is the excess of (i) revenues from the Trust properties plus any decrease in cash reserves previously established for contingent liabilities and any other cash receipts of the Trust over (ii) the expenses and payments of liabilities of the Trust plus any increase in cash reserves for contingent liabilities.
Transfer
Units are transferable on the records of the Trustee upon surrender of any certificate in proper form for transfer (or in compliance with the Trustee’s procedures for uncertificated Units) and compliance with such reasonable regulations as the Trustee may prescribe. No service charge is made to the transferor or transferee for any transfer of a Unit, but the Trustee may require payment of a sum sufficient to cover any tax or governmental charge that may be imposed in relation to such transfer. Until any such transfer, the Trustee may conclusively treat the holder of a Unit shown by its records as the owner of that Unit for all purposes. Any such transfer of a Unit will, as to the Trustee, vest in the transferee all rights of the transferor at the date of transfer, except that the transfer of a Unit after the Monthly Record Date for a distribution will not transfer the right of the transferor to such distribution.
The transfer of Units by gift and the transfer of Units held by a decedent’s estate, and distributions from the Trust in respect thereof, may be restricted under applicable state law.
Equiniti Trust Company, LLC (formerly 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.
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, 3838 Oak Lawn Avenue, Suite 1720, Dallas, Texas, 75219, telephone number 1-855-588-7839, email address trustee@sbr-sabine.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.sbr-sabine.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unit holders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units, including the issuance of Internal Revenue Service (the “Service”) Forms 1099 and certain written tax statements. Unit holders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.
Liability of Unit Holders
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.
FEDERAL TAXATION
The tax consequences to a Unit holder of the ownership and sale of units will depend in part on the Unit holder’s tax circumstances. Each Unit holder should therefore consult the Unit holder’s tax advisor about the federal, state and local tax consequences to the Unit holder of the ownership of units.
In May 1983, the Service ruled that the Trust is classified as a grantor trust for federal income tax purposes and not as an association taxable as a corporation. Accordingly, the income and deductions of the Trust are reportable directly by Unit holders for federal income tax purposes. The Service also ruled that Unit holders would be entitled to deduct cost depletion with respect to their investment in the Trust and that the transfer of a Unit in the Trust would be considered to be a transfer of a proportionate part of the Royalty Properties held by the Trust.
Transferees of Units transferred after October 11, 1990, may be entitled to a percentage depletion deduction attributable to such Units, if the percentage depletion deduction exceeds cost depletion. Unlike cost depletion, percentage depletion is not limited to a Unit holder’s depletable tax basis in the Units. Rather, a Unit holder is entitled to a percentage depletion deduction as long as the applicable Royalty Properties generate gross income. Unit holders should compute both percentage depletion and cost depletion from each property and claim the larger amount as a deduction on their income tax returns.
If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and if the adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Internal Revenue Code (the “Code”), the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of Section 1254 property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The Service could take the position that a Unit holder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit.
Unit holders must maintain records of their adjusted basis in their Trust Units (generally their cost less prior depletion deductions), make adjustments for depletion deductions to such basis, and use the adjusted basis for the computation of gain or loss on the disposition of the Trust Units.
In order to facilitate the creation of the Trust and to avoid the administrative expense and inconvenience of daily reporting to Unit holders by the Trustee, the conveyances by Sabine Corporation of the Royalty Properties located in five of the six states (Florida, Mississippi, New Mexico, Oklahoma, and Texas) provided for the execution of an escrow agreement by Sabine Corporation and InterFirst (the initial trustee of the Trust), in its capacities as trustee of the Trust and as escrow agent. The conveyances by Sabine Corporation of the Royalty Properties located in Louisiana provided for the execution of a substantially identical escrow agreement by Sabine Corporation and Hibernia National Bank in New Orleans, in the capacities of escrow agent and of trustee of Sabine Louisiana Royalty Trust. The Trust now only has one escrow agent, which is the Trustee, and a single escrow agreement.
Pursuant to the terms of the escrow agreement and the conveyances of the Royalty Properties, the proceeds of production from the Royalty Properties for each calendar month, and interest thereon, are collected by the escrow agent and are paid to and received by the Trust only on the next Monthly Record Date. The escrow agent has agreed to endeavor to assure that it incurs and pays expenses and fees for each calendar month only on the next Monthly Record Date. The Trust Agreement also provides that the Trustee is to endeavor to assure that income of the Trust will be accrued and received and expenses of the Trust will be incurred and paid only on each Monthly Record Date.
Assuming that the escrow arrangement is recognized for federal income tax purposes and that the Trustee, as escrow agent, is able to control the timing of income and expenses, as stated above, cash and accrual basis Unit holders should be treated as realizing income only on each Monthly Record Date. The Trustee, as escrow agent, may not be able to cause third party expenses to be incurred on each Monthly Record Date in all instances. Cash basis Unit holders, however, should be treated as having paid all expenses and fees only when such expenses and fees are actually paid by the Trustee. Even if the escrow arrangement is recognized for federal income tax purposes, however, accrual basis Unit holders might be considered to have accrued expenses when such expenses are incurred rather than on each Monthly Record Date when paid.
No ruling was requested from the Service with respect to the effect of the escrow arrangements when established. Due to the absence of direct authority and the factual nature of the characterization of the relationship among the escrow agents, PEC and the Trust, no opinion was expressed by legal counsel with respect to the tax consequences of the escrow arrangements. If the escrow arrangement is recognized, the income from the Royalty Properties for a calendar month and interest income thereon will be taxed to the holder of the Unit on the next Monthly Record Date without regard to the ownership of the Unit prior to that date. The Trustee is treating the escrow arrangement as effective for tax purposes and furnishes tax information to Unit holders on that basis.
The Service might take the position that the escrow arrangement should be ignored for federal tax purposes. In such case, the Trustee could be required to report the proceeds from production and interest income thereon to the Unit holders on a daily basis, in accordance with their method of accounting, as the proceeds from production and interest thereon were received or accrued by the escrow agent. Such reporting could impact who is taxed on the production and interest income and result in a substantial increase in the administrative expenses of the Trust. In the event of a transfer of a Unit, the income and the depletion deduction attributable to the Royalty Properties for the period up to the date of transfer would be allocated to the transferor, and the income and depletion deduction attributable to the Royalty Properties on and after the date of transfer would be allocated to the transferee. Such allocation would be required even though the transferee was the holder of the Unit on the next Monthly Record Date and, therefore, would be entitled to the monthly income distribution. Thus, if the escrow arrangement is not recognized, a mismatching of the monthly income distribution and the Unit holder’s taxable income and deductions could occur between a transferor and a transferee upon the transfer of a Unit.
Unit holders of record on each Monthly Record Date are entitled to receive monthly distributions. See “Description of Units - Distributions of Distributable Income” above. The terms of the escrow agreement and the Trust Agreement, as described above, seek to assure that taxable income attributable to such distributions will be reported by the Unit holder who receives such distributions, assuming that such holder is the holder of record on the Monthly Record Date. In certain circumstances, however, a Unit holder may be required to report taxable income attributable to their Units but the Unit holder will not receive the distribution attributable to such income. For example, if the Trustee establishes a reserve or borrows money to satisfy debts and liabilities of the Trust, income used to establish such reserve or to repay such loan will be reported by the Unit holder, even though such income is not distributed to the Unit holder.
Interest and royalty income attributable to ownership of Units and any gain on the sale thereof are considered portfolio income, and not income from a “passive activity,” to the extent a Unit holder acquires and holds Units as an investment and not in the ordinary course of a trade or business. Therefore, interest and royalty income attributable to ownership of Units generally may not be offset by losses from any passive activities.
As a result of the 2017 Tax Cuts and Jobs Act (the “TCJA”), for tax years beginning after December 31, 2017, and before January 1, 2026, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Under the TCJA, for such tax years, personal exemptions and deductions for miscellaneous itemized deductions are not allowed. The U.S. federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and capital gains.
Individuals may incur expenses in connection with the acquisition or maintenance of Trust Units. For tax years beginning before January 1, 2018, and after December 31, 2025, these expenses, which are different from a Unit holder’s share of the Trust’s administrative expenses discussed above, may be deductible as “miscellaneous itemized deductions” only to the extent that such expenses exceed 2% of the individual’s adjusted gross income. Under the TCJA, for tax years beginning after December 31, 2017, and before January 1, 2026, miscellaneous itemized deductions are not allowed.
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.
Florida, Louisiana, Mississippi, New Mexico and Oklahoma. Florida does not impose an individual income tax. Florida imposes an income tax on resident and nonresident corporations (except for S corporations not subject to the built-in gains tax or passive investment income tax), which will apply to royalty income allocable to a corporate Unit holder from Royalty Properties located within Florida. Louisiana, Mississippi, New Mexico and Oklahoma each impose an income tax applicable to both resident and nonresident individuals and/or corporations (subject to certain exceptions for S corporations and limited liability companies, depending on their treatment for federal tax purposes), which will apply to royalty income allocable to a Unit holder from Royalty Properties located within these states. 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 nonresidents of oil and gas proceeds derived from royalty interests. To reduce the administrative burden imposed by these rules, the Trustee has opted to allow the payors of oil and gas proceeds to withhold on royalty payments made to the Trust. The Trust files New Mexico tax returns, obtains a refund, and distributes that refund to Unit holders.
Withholding at the Trust level reduces the amount of cash available for distribution to Unit holders. Unit holders who transfer their Units before the New Mexico tax refunds are received by the Trust or after the refunds are received but before the next Monthly Record Date will not receive any portion of the refund. As a result, such Unit holders may incur a double tax - first through the reduced distribution received from the Trust and second by the tax payment made directly to the New Mexico taxing authority with the filing of their New Mexico income tax returns (if applicable). With respect to Oklahoma, the Trust has historically claimed and received refunds for withholding and distributed these refunds to Unit holders. However, beginning in 2018, the Trust’s refund claims have been denied, and the Trust may not qualify for an exemption from withholding in Oklahoma. The Trustee is actively working with the Oklahoma Tax Commission to resolve the issue. Unless the Trust is eligible to obtain an exemption from Oklahoma withholding tax or obtain a refund of Oklahoma withholding tax, Unit holders subject to Oklahoma income tax would be required to file an Oklahoma income tax return in order to claim a credit or refund for any Oklahoma withholding tax attributable to such Unit holder’s Units. A Unit holders entitlement to such a refund or credit will be dependent upon the relevant facts and circumstances of such Unit holder.
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, land use, well construction, water use, prevention of waste, waste disposal, pollution, and protection of human health and safety and the environment. These laws, regulations and orders have in the past, and may again, restrict the rate of oil and gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders.
Laws affecting the oil and gas industry and the distribution of its products are under constant review for amendment or expansion, frequently becoming more stringent and are increasing the regulatory burden over time. Numerous governmental departments and agencies are authorized by statute or other laws to issue, and have issued, rules and regulations binding on the oil and gas industry which are often difficult and costly to comply with and which impose substantial penalties or other liabilities for the failure to comply.
Natural Gas
Prices for the sale of natural gas, like the sale of other commodities, are governed by the marketplace and the provisions of applicable gas sales contracts. The Federal Energy Regulatory Commission (“FERC”), which principally is responsible for regulating interstate transportation and the sale of natural gas, has taken significant steps in the implementation of a policy to restructure the natural gas pipeline industry to promote full competition in the sales of natural gas, so that all natural gas suppliers, including pipelines, can compete equally for sales customers. This policy has been implemented largely through restructuring proceedings and is subject to continuing refinement. The effects of this policy are now presumably fully reflected in the natural gas markets. The current policy of FERC continues to promote increased competition among gas industry participants. Accordingly, various regulations and orders have been proposed and implemented to encourage nondiscriminatory open-access transportation by interstate pipelines and to provide for the unbundling of pipeline services so that such services may also be furnished by non-pipeline suppliers on a competitive basis.
Many other statutes, rules, regulations and orders affect the pricing or transportation of natural gas. Some of the provisions are and will be subject to court or administrative review. Consequently, uncertainty as to the ultimate impact of these regulatory provisions on the prices and production of natural gas from the Royalty Properties is expected to continue for the foreseeable future.
Environmental Regulation
General. Activities on the Royalty Properties are subject to existing stringent and complex federal, tribal, state and local laws (including case law), rules and regulations governing health, safety, environmental quality and pollution control. Absent the occurrence of an extraordinary event, the cost of compliance with existing federal, tribal, state and local laws, rules and regulations regulating health, safety, or the protection of the environment are not expected to have a material adverse effect upon the Trust or Unit holders. Those laws and regulations may impose numerous obligations that are applicable to the operations of the Royalty Properties, including the acquisition of a permit before conducting construction, drilling, production, underground injection or associated operational activities; the reporting of the types and quantities of various substances stored, processed, transported, generated, disposed of, or released in connection with operation of the Royalty Properties; planning and preparedness for spill and emergency response activities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, endangered or threatened species habitat and other sensitive or protected areas; the imposition of substantial liabilities for pollution resulting from operations including waste generation, air emissions, water discharges and current and historical waste disposal practices; the remediation of materials released in the environment; the application of specific health and safety criteria addressing worker protection and public health and safety; and the installation of emission monitoring and/or pollution control equipment. Failure, however, to comply with these laws, rules and regulations may result in the assessment of administrative, civil or criminal fines or penalties; the imposition of investigatory ongoing monitoring, or remedial obligations; and the issuance of injunctions or orders limiting or preventing some or all of the operations. Under certain environmental laws and regulations, the operators of the Royalty Properties could also be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination, in either case, whether at a drill or production or storage site or a waste disposal facility, regardless of whether the operators were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time the actions were taken.
Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, and comparable state laws impose liability, regardless of fault or the legality of the conduct at the time it occurred, on certain classes of persons that own or owned property where release of a “hazardous substance” occurred or contributed to the release of a “hazardous substance” into the environment. These persons include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who generated, transported, disposed or arranged for the transport or disposal of a
hazardous substance. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs of such an action, including the costs of certain health studies. In addition, from time to time, EPA may designate additional materials as hazardous substances under CERCLA, which could result in additional investigation and remediation at current Superfund sites, or reopener of Superfund sites that previously received regulatory closure. For example, EPA issued a final rule that became effective on July 8, 2024, designating as "hazardous substances" under CERCLA perfluorooctanoic acid and perfluorooctanesulfonic acid, which have been commonly used in a variety of industrial and consumer products. In the course of operations, the working interest owner and/or the operator of Royalty Properties may have generated and may generate wastes that may fall within CERCLA’s definition of “hazardous substances.” The operator of the Royalty Properties or the working interest owners may be responsible under CERCLA for all or part of the costs to clean up sites at which such substances have been disposed. Although the Trust is not the operator of any Royalty Properties, or the owner of any working interest, its ownership of royalty interests could cause it to be responsible for all or part of such costs to the extent responsibility under CERCLA could be imposed on such parties as “owners.”
Solid and Hazardous Waste. The Royalty Properties have produced oil and/or gas for many years and, in connection with that production, managed waste, such as drilling fluids and produced water, that is subject to regulation under environmental laws. Although the Trust has no knowledge of the procedures followed by the operators of the Royalty Properties in this regard, hydrocarbons or other solid 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. 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 currently regulated as nonhazardous waste and are exempted from hazardous waste regulation under RCRA, this exemption is subject to being limited or lost, and the loss of this exemption would result in more stringent regulation of these types of waste. Moreover, these wastes and other wastes may be otherwise regulated by the EPA or state agencies. In addition, in the ordinary course of operation of the Royalty Properties, industrial wastes such as paint wastes and waste solvents may be regulated as hazardous waste under RCRA or considered hazardous substances under CERCLA.
Disposal Wells
The federal Safe Drinking Water Act (“SDWA”), the Underground Injection Control (“UIC”) program promulgated under the SDWA and analogous state programs regulate the drilling and operation of salt water disposal and injection wells. EPA directly administers the UIC program in some states and in others, administration is delegated to the state. Permits must be obtained before drilling salt water disposal and injection wells, and mechanical integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater. In addition, because some states have become concerned that the injection or disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering additional regulations regarding the potential seismic impacts of such disposal methods. Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Royalty Properties to dispose of produced water and ultimately increase the cost of operation of the Royalty Properties or delay production schedules. For example, in 2014, the Railroad Commission of Texas (“RRC”) published a final rule governing permitting or re-permitting of disposal wells that requires, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Furthermore, in response to a number of earthquakes in recent years in the Midland Basin in Texas, the RRC announced in September 2021 that it will not issue any new saltwater disposal (“SWD”) well permits in an area known as the Gardendale Seismic Response Area (“SRA”), and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well. In December 2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits. The RRC has since identified two additional SRAs (the Northern Culberson-Reeves (“NCR”) SRA and the Stanton SRA), required operators in the NCR SRA and Stanton SRA to implement seismic response plans, (which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff), expanded both the Gardendale and NCR SRAs in response to additional earthquakes in the area suspended all (totaling 23) deep disposal well permits in the NCR SRA (effective January 12, 2024), and, as recently as May 2024, issued revised Response Plans for the Stanton SRA with proposed additional daily injection volume curtailments. Such restrictions and requirements could limit the Royalty Properties’ oil and gas well exploration and production activities or increase the cost of those activities if wastewater disposal options become limited.
In addition, several cases have in recent years put a spotlight on the issue of whether injection wells may be regulated under the Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. Following a request for comment issued by EPA in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs, the Agency concluded in April 2019 that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, in April 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. In November 2023, EPA issued draft guidance outlining the factors that may be considered when evaluating whether discharges through groundwater may be the “functional equivalent” of a direct discharge and subject to regulation under the CWA National Pollutant Discharge Elimination System permitting program and describing the types of information that should be used in the determination. Comments on the draft guidance were due to the agency by December 27, 2023, and to date EPA has not yet finalized the guidance. If in the future CWA permitting is required for any saltwater injection wells as a result of the Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund, the costs associated with operations of the Royalty Properties could increase.
Threatened and Endangered Species, Migratory Birds and Natural Resources. Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds and their habitat, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act (“MTBA”), the Bald and Golden Eagle Protection Act, the Clean Water Act, and CERCLA. The United States Fish and Wildlife Service (“USFWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to, species or damage to wetlands, habitat or natural resources occur, or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities. Damages, including natural resources damages, and criminal penalties for harm to species, habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, produced water, hazardous substances or other regulated materials may be sought. The first Trump administration promulgated a rule in January 2021 that formalized a December 2017 Department of Interior (“DOI”) interpretation of the MBTA as applying only to the intentional killing of birds and not to the accidental but preventable killing of protected birds that occurs as the result of otherwise lawful activities. However, the rule was relatively short-lived. In October 2021, the DOI under the Biden administration issued a rule to reverse the agency’s position on incidental takes of migratory birds, and permanently revoked and withdrew the underlying December 2017 DOI interpretation, citing a federal district court’s opinion in Natural Resources Defense Council v. U.S. Dep’t of the Interior, 478 F. Supp. 3d, 469 (S.D.N.Y. 2020), that the underlying December 2017 DOI interpretation was in clear conflict with long-standing interpretation of the MBTA, and the Second Circuit’s subsequent dismissal of the appeal of the district court’s decision. The reversal of the Trump administration’s January 2021 rule took effect on December 3, 2021.
Water Discharges. The CWA and analogous state laws impose restrictions and strict controls on the discharge of pollutants and fill material, including sediments from construction and spills and leaks of oil and other substances, into regulated waters, including 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” or “jurisdictional waters”), has been in flux the past several years due to recent rulemaking and associated litigation concerning the WOTUS definition resulting in the rule taking effect at times in some states but not others and creating definitions that are more inclusive of certain waters effective in some states and those that are less inclusive effective in other states. EPA and USACE’s WOTUS definition rulemaking published in the Federal Register on January 18, 2023 (the January 2023 Rule) incorporated “relatively permanent” and “significant nexus” standards for determining jurisdiction over adjacent wetlands and additional waters, expanding the types of waters that could be considered WOTUS; however, this WOTUS definition was litigated and eventually amended on August 29, 2023, when EPA and USACE issued a final rule to conform the WOTUS definition to the U.S. Supreme Court’s May 25, 2023, decision in Sackett v. Environmental Protection Agency, which invalidated parts of the January 2023 Rule. With the August 2023 rulemaking, EPA and USACE implemented a narrower definition of WOTUS by, for example, removing “interstate wetlands”; redefining “adjacent” to mean “having a continuous surface connection”; and removing the “significant nexus” standard from the provisions regarding tributaries, adjacent wetlands, and intrastate lakes and ponds. 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 fines and penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
Climate Change/Air Emissions. Mitigating climate change has become the subject of an important public policy debate and the basis for new legislation proposed by the United States Congress and certain states. Some states have also adopted climate change statutes and regulations. The International Energy Agency (“IEA”) estimates in its World Energy Outlook 2024 that growth in global energy demand is expected to slow due to efficiency improvements, electrification, and quick expansion of renewables. In addition, the IEA predicts that oil and natural gas, along with coal, are each expected to reach their high point in global energy demand before 2030, with their combined percentage of global energy supply expected to drop below eighty percent (80%) before that time, and various models showing a range in decline of fossil fuel energy supply between 75% to 65% of total energy supply by 2030 and 60% to 15% of total energy supply by 2050. In addition, the IEA notes that China's electricity demand is significantly larger than other countries, and that the growth in demand for fossil fuels could be tempered and decrease further if the growth of China’s investment in and commitments to developing clean power generation sources outpace its investment in fossil fuel-generated energy. Similarly, the nature of energy investments and commitments by other high-energy-demand growth areas, such as India and Indonesia will impact the speed at which non-fossil fuel sources of power can keep up with global electricity demand. The United States, depending on which President has been in office, has participated (during the Biden administration) or not (during the two Trump administrations) in the Paris Climate Accord, a voluntary international agreement with the goal of limiting global climate change to not more than 2 degrees Celsius (or less); 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 had also set ambitious domestic targets for curbing climate change, such as making the U.S. power sector carbon-neutral by 2035. While changes in U.S. presidential administrations could increase or lessen the relative impacts of climate policies and regulations on the oil and natural gas industry, the adoption and implementation of any international, federal, or state GHG-emission reduction commitments, legislation, or regulations or other restrictions or imposition of taxes, fees, or limits on emissions of GHGs could result in increased development, operation, and compliance costs, additional operating restrictions on the Royalty Properties, and additional regulatory burdens, and thus decrease revenue to the Trust.
In response to the April 2007 U.S. Supreme Court decision in Massachusetts vs. EPA finding that GHGs are air pollutants under the Clean Air Act (“CAA”), 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 GHG monitoring and reporting regulations,that since 2012, have required annual reporting of GHGs by persons operating certain types of industrial operations, including oil and gas production, transmission and storage operations that emit 25,000 metric tons or more of carbon dioxide equivalent per year (the “GHG Reporting Rule"). 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 2024 calendar year methane emissions from oil and gas operations that are required to report their GHG emissions under the GHG Reporting Rule. EPA’s final rule to implement the fee requirements, “Waste Emissions Charge for Petroleum and Natural Gas Systems,” was published on November 18, 2024, and took effect on January 17, 2025. Although the Trump presidential administration may make efforts to rollback or revise these rules in connection with its focus on promotion of the oil and natural gas production, the rules are currently in effect, and oil and gas operators subject to the rule must pay fees on 2024 methane emissions by September 2, 2025, and by August 31 for subsequent years. Compliance with these rules requires enhanced record-keeping practices and, thus, may increase operating costs associated with the Royalty Properties and may decrease net revenue to the Trust.
In addition, on May 9, 2024, pursuant to its authority under Section 111 of the CAA to set emission standards for new and existing power plants based on the “best system of emission reduction,” EPA finalized new source performance standards for GHG emissions from fossil fuel-fired stationary combustion turbine electricity generating units and from certain fossil-fuel fired steam generating units. Among other requirements, the rule, effective July 8, 2024, revised CAA New Source Performance Standards (“NSPS”) for new or substantially modified natural gas-fired power plants based on the use of more efficient fuels, simple cycle operation, and the implementation of carbon capture and sequestration/storage technology. The rule also revises the NSPS for GHG emissions from fossil fuel-fired steam generating units that undertake major modifications. Adoption of rules that either place additional limits on GHG emissions from fossil fuel-fired electricity or steam generating units or otherwise incentivize non-fossil fuel generated sources of energy could reduce demand for oil and gas generally, including oil and gas produced from the Royalty Properties and could increase the cost of operations of the Royalty Properties, which could result in a loss of reserves or revenues to the Trust.
Pursuant to the CAA and state laws concerning the permitting of air emissions, certain new and modified sources of air emissions are subject to air permitting authorizations for construction and operation, and sources of air emissions at the Royalty Properties are no exception to these requirements. In addition to air permitting requirements, certain sources of emissions involved in oil and gas operations are subject to source-specific emission standards pursuant to CAA New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants. For example, on August 16, 2012, EPA issued a final rule that established
new source performance standards for volatile organic compounds (“VOCs”) and sulfur dioxide, an air toxics standard for sources of oil and natural gas production, and an air toxics standard for sources of natural gas transmission and storage. The rule applied to certain oil and natural gas sources that were constructed, modified, or reconstructed after August 23, 2011, and required that all hydraulically fractured or refractured natural gas wells must have been completed using so-called “green completion” technology, which significantly reduces VOC emissions. Limiting emissions of VOCs also has the co-benefit of limiting methane, a GHG. In addition, these regulations, referred to as NSPS Subpart OOOO, apply to storage tanks and other equipment in the affected oil and natural gas industry segments. In June 2016, EPA issued a suite of new final regulations, referred to as NSPS Subpart OOOOa, designed to limit methane, VOCs and other emissions from new and existing sources in the oil and gas sector. Among other requirements, the NSPS Subpart OOOOa rules extended green completion requirements to newly fractured and re-fractured oil wells. Furthermore, in December 2023, EPA announced additional final NSPS OOOO program rules referred to as Subparts OOOOb and OOOOc, which are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective. The rules impose additional methane and VOC emissions limitations from new, modified, and reconstructed sources; and will regulate existing sources for the first time under the NSPS Subpart OOOOc program by requiring states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities. Legal challenges, including by states, to the recently finalized NSPS Subparts OOOOb and OOOOc rules have ensued. Further, the Trump presidential administration may make efforts to rollback or revise these rules in connection with its focus on promotion of oil and natural gas production. Although the bulk of the 2012 and 2016 standards and the new OOOOb and OOOOc rules are currently in effect, future implementation and the ultimate scope of VOC and methane emission regulations for the oil and gas production, transmission, and storage industry segments are uncertain at this time as a result of expected new rulemakings, ongoing and expected legal challenges, and actions by the Trump presidential administration that are expected to affect, in particular, implementation of the NSPS Subpart OOOOb and OOOOc rules.
In part in response to the Inflation Reduction Act requirement for operators to pay royalties on “all gas that is consumed or lost by venting, flaring, or negligent releases through any equipment during upstream operations,” in April 2024, the Bureau of Land Management (“BLM”) finalized the Waste Prevention, Production Subject to Royalties, and Resource Conservation Rule (also known as the “Waste Prevention Rule”), which replaces the BLM’s existing venting and flaring requirements in its 1979 Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases: Royalty or Compensation for Oil and Gas Lost (“NTL -4A”) and includes, among others, requirements for self-certification statements or waste minimization plans, flaring limits, leak detection and repair obligations, and for considering oil and gas “unavoidably lost” and, thus, not subject to royalty payments. Implementation of the Waste Prevention Rule could result in increased compliance costs of operation of Royalty Properties on federal and Indian lands.
In addition, spurred by increasing concerns regarding climate change, the oil and gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals. Environmental, social, and governance (“ESG”) goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and shareholders across the industry. While reporting on ESG metrics remains voluntary, access to capital and investors is likely to favor companies with robust ESG programs in place. Furthermore, in March 2024 the SEC adopted rule amendments that require public companies to disclose certain climate-related information in their public filings, including information about a company’s climate-related risks that have materially impacted, or are reasonably likely to have a material impact on, its business strategy, results of operations, or financial condition. The new rules also required certain disclosure requirements related to severe weather events and other natural conditions in a company’s audited financial statements. However, the SEC stayed implementation of the rules until legal challenges to the rules could be resolved, and, following installation of the second Trump presidential administration, is reassessing its position in the litigation. Ultimately, if these initiatives and ESG rulemakings are ultimately reinstated or amended to require additional ESG-related disclosures, they 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. To the extent diesel fuels are used in hydraulic fracturing activities on properties underlying the Royalty Properties, this guidance will apply, and may cause additional costs and delays in development of the Royalty Properties.
Congress and various states, including Texas, Louisiana, Mississippi, New Mexico and Oklahoma, have proposed or adopted legislation regulating or requiring disclosure of the chemicals in the hydraulic fracturing fluid that is used in oil and gas drilling operations. Texas, New Mexico and Oklahoma, among other states require oil and gas operators to disclose the chemicals on the Frac Focus website.
In addition, on March 20, 2015, the BLM released new regulations governing hydraulic fracturing operations on federal and Indian lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. In December of 2017, the BLM rescinded the 2015 regulations, and environmental organizations and the State of California sued the BLM and the Secretary of the U.S. Department of the Interior over the repeal. In March 2020, the Northern District of California issued a ruling in favor of the BLM, upholding the BLM’s rescission of the 2015 regulations. The case has been administratively closed since November 15, 2021; however, if the regulations are reinstated, or if similar regulations are re-proposed, such regulation of hydraulic fracturing operations
may result in additional levels of regulatory complexity with respect to existing state regulations that could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase costs of compliance of Royalty Properties on federal and Indian Lands.
A number of governmental agencies have conducted studies on hydraulic fracturing. For example, in 2016 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, which could increase the cost to operate the Royalty Properties and could have an adverse effect on the net proceeds payable to the Trust.
OSHA and Other Laws and Regulations. The 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.
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 decreased from $79.60 in 2023 to $77.04 in 2024. In 2023, oil prices declined in the first few months of 2023, but as the year went on, the price of oil increased somewhat. However, average 2023 prices were still below that of the previous year. Oil prices stayed fairly constant throughout 2024, with increases in the spring and summer of 2024, followed by decreases throughout the remainder of the year. The Trustee believes that the price of oil was affected by higher inflation, along with uncertainty in the economy due to the November U.S. presidential election.
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 2024 on natural gas volumes sold of $1.88 per thousand cubic feet (“Mcf”) represented a decrease from the $3.52 per Mcf average price received in 2023, due largely to warmer weather in the fall and early winter 2024, higher inflation, along with uncertainty brought about by the November U.S. presidential election which put downward pressure on the price. This continued oversupply contributed to lower gas prices in the fourth quarter of 2024.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
Crude oil and natural gas prices are volatile and fluctuate in response to a number of factors; Lower prices could reduce the net proceeds payable to the Trust and Trust distributions.
The Trust’s monthly distributions are highly dependent upon the prices realized from the sale of crude oil and natural gas and a material decrease in such prices could reduce the amount of cash distributions paid to Unit holders. Crude oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust. Factors that contribute to price fluctuation include, among others:
•political conditions in major oil producing regions, especially in Eastern Europe and the Middle East,
•worldwide economic and geopolitical conditions;
•weather conditions;
•trade barriers and tariffs;
•public health concerns, such as COVID-19;
•the supply and price of domestic and foreign crude oil or natural gas;
•the level of consumer demand;
•the price and availability of and purchaser or consumer preference for alternative fuels;
•the proximity to, and capacity of, transportation facilities;
•the effect of worldwide energy conservation measures and governmental policies and regulatory incentives for investment in non-fossil fuel energy sources; and
•the nature and extent of governmental regulation and taxation.
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:
•historical production from the area compared with production rates from similar producing areas;
•the effects of governmental regulation;
•assumptions about future commodity prices, production and taxes;
•the availability of enhanced recovery techniques; and
•relationships with landowners, working interest partners, pipeline companies and others.
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.
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, continued hostilities in Eastern Europe and the Middle East or other military campaigns could decrease Trust distributions or the market price of the Units.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as 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, or other sustained military campaigns could adversely affect Trust distributions or the market price of the Units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which the operators developing the 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 by promoting alternatives. These include the adoption of cap and trade regimes, carbon taxes, trade tariffs, minimum renewable usage requirements, restrictive permitting, increased mileage and other efficiency standards, mandates for sales of electric vehicles, mandates for use of specific fuels or technologies, and other incentives or mandates designed to support transitioning to lower-emission energy sources. Political and other actors and their agents also increasingly seek to advance climate change objectives indirectly, such as by seeking to reduce the availability or increase the cost of financing and investment in the oil and gas sector. Depending on how policies are formulated and applied, such policies could impact the ability and costs of the operators of the 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 decreases market prices could have a material impact on the distributable income of the Trust.
The Trustee may be subject to attempted cybersecurity disruptions from a variety of sources including state-sponsored actors.
The Trustee maintains robust cybersecurity protocols including, but not limited to technological capabilities that prevent and detect disruptions; computer workstations and programs protected with passwords and passphrases, as well as employee training throughout the year on financial regulations and cybersecurity followed up by testing of that knowledge. Other, non-technical protocols include securing of documents and work areas that could contain personal, non-public information and independent verification of information changes by outside vendors. If the measures taken to protect against cybersecurity disruptions prove to be insufficient or if proprietary data is otherwise not protected, the Trustee or 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 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.
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 SEC, 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 recorded 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 made 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.
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.
Pandemics or other public health concerns, such as COVID-19, or the novel coronavirus, and any measures taken to mitigate the impact of such health concerns, could 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 Royalty Properties, have been, and may in the future be, adversely impacted by public health concerns such as COVID-19 and measures taken to mitigate its impact.
The industry experienced a sharp and rapid decline in the demand for oil and natural gas as the U.S. and global economy in 2020, and commodity prices, were negatively impacted as economic activity was curtailed in response to the COVID-19 pandemic, as well as due to other geopolitical factors. Future pandemics or other significant public health events could have a material adverse effect on operators’ business and financial condition which would likely have an adverse effect on Trust distributions.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
The Trust has not received any written comments from the SEC staff regarding its periodic or current reports under the Act more than 180 days prior to December 31, 2024, which comments remain unresolved.

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ITEM 2. PROPERTIES
Item 2. Properties.
The assets of the Registrant consist principally of the Royalty Properties, which constitute interests in gross production of oil, gas and other minerals free of the costs of production. The Royalty Properties consist of royalty and mineral interests, including landowner’s royalties, overriding royalty interests, minerals (other than executive rights, bonuses and delay rentals), production payments and any other similar, nonparticipatory interest, in certain producing and proved undeveloped oil and gas properties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma and Texas. These properties are represented by approximately 5,400 tracts of land. Approximately 2,950 of the tracts are in Oklahoma, 1,750 in Texas, 330 in Louisiana, 200 in New Mexico, 150 in Mississippi and 12 in Florida.
The following table summarizes total developed and proved undeveloped acreage represented by the Royalty Properties at December 31, 2024. For changes in proved reserves, see Part II, Item 8 “Financial Statements - Notes to Financial Statements - Note 8 Supplemental Oil and Gas Information (Unaudited)”.
Mineral and Royalty
State
Gross Acres
Net Acres
Florida
5,448
Louisiana
244,391
23,682
Mississippi
75,489
9,713
New Mexico
112,294
9,141
Oklahoma
381,538
67,558
Texas
1,273,132
105,760
Total
2,092,292
216,551
Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate count of the number of wells located on the Royalty Properties, the number of exploratory or development wells drilled on the Royalty Properties during the periods presented by this report, or the number of wells in process or other present activities on the Royalty Properties, and the Registrant cannot readily obtain such information.
The Trust owns minerals in six states - Texas, Oklahoma, Louisiana, Mississippi, New Mexico and Florida. This gives the Trust exposure within a number of producing basins. The chart below gives the approximate net and gross acres that the Trust owns in the most prominent producing basins within its footprint.
This broad exposure means that the Trust minerals are currently producing and under lease in virtually every major active play within these basins. In the Texas Gulf Coast, these plays include the Eagle Ford and Austin Chalk. In the East Texas Basin, active plays include the Travis Peak, Bossier and Haynesville. The Mississippi Salt Basin has not been as active in recent years, 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, 2024.
Acreage by Basin
Basin
Gross Acres
Net Acres
Permian
909,808
43,300
Anadarko
275,200
59,300
Gulf Coast
364,500
34,800
East Texas
116,000
33,500
Arkoma
92,200
18,600
Mississippi Salt
71,500
9,300
Various Others
263,084
17,751
Total
2,092,292
216,551
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 December 31, 2024 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 Part II Item 8 “Financial Statements - Notes to Financial Statements - Note 8 Supplemental Oil and Gas Information (Unaudited)” 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 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.
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 21, 2025
Argent Trust Company
3838 Oak Lawn Avenue, Suite 1720
Dallas, Texas 75219
Ladies and Gentlemen:
Pursuant to the request of Sabine Royalty Trust (the “Trust”), this report of third party presents an independent evaluation, as of December 31, 2024, 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 21, 2025. 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 December 31, 2024. 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, 2024. 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 S&P Global; Copyright 2024 S&P Global. 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.
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
(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 31, 2024, 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 2024. Estimated cumulative production, as of December 31, 2024, 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 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 45 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 $76.32 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 $72.91 per barrel of oil and condensate and $18.53 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 $2.13 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 $1.795 per thousand cubic feet of gas.
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 herein 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.
Summary of Conclusions
DeGolyer and MacNaughton has performed an independent evaluation of the extent and value of the estimated net proved oil, condensate, NGL, and gas reserves of certain properties in which the Trust has represented it holds an interest. The estimated net proved developed producing reserves, as of December 31, 2024, of the properties evaluated herein were based on the definition of proved
developed reserves of the SEC and are summarized by state as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
Estimated by DeGolyer and MacNaughton
Net Proved Developed Producing Reserves
as of December 31, 2024
State
Oil and
Condensate
(Mbbl)
NGL
(Mbbl)
Total
Liquids
(Mbbl)
Sales
Gas
(MMcf)
Florida
-
Louisiana
Mississippi
-
New Mexico
Oklahoma
1,264
13,749
Texas
5,136
1,883
7,019
49,112
Total
6,361
2,514
8,872
64,236
The estimated future revenue to be derived from the production and sale of the net proved developed producing reserves, as of December 31, 2024, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):
Proved
Developed
Producing
(M$)
Future Gross Revenue
625,585
Production Taxes
32,017
Ad Valorem Taxes
23,412
Transportation Expenses
20,816
Future Net Revenue
549,340
Present Worth at 10 Percent
280,325
Note: Future income taxes have not been taken into account in the preparation of these estimates.
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 December 31, 2024, 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
\s\ Dilhan Ilk
Dilhan Ilk, P.E.
Executive Vice President
DeGolyer and MacNaughton
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:
1.That I am an Executive Vice President with DeGolyer and MacNaughton, which firm did prepare this report of third party addressed to Argent Trust Company dated February 21, 2025, and that I, as Executive Vice President, was responsible for the preparation of this report of third party.
2.That I attended Istanbul Technical University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005, and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 14 years of experience in oil and gas reservoir studies and reserves evaluations.
\s\ Dilhan Ilk
Dilhan Ilk, P.E.
Executive Vice President
DeGolyer and MacNaughton
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 2025 will be approximately $4,250,000.
The present value of future net revenue of the Trust’s proved developed reserves increased from $257,549,720 at December 31, 2023, to $280,325,131 at December 31, 2024. This increase resulted primarily from the higher volumes in the December 31, 2024, reserve report compared to the December 31, 2023, reserve report.
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 18, 2025, NYMEX posted oil prices were approximately $72.21 per barrel, which compared to the average posted price of $72.91 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 18, 2025, NYMEX posted gas prices were $6.40 per million British thermal units. The use of such price, as compared to the average posted price of $1.795 per million British thermal units, used to calculate future net revenue for the Trust’s proved developed reserves would result in an increase 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.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings.
There are no material pending legal proceedings to which the Registrant is a party or of which any of its property is the subject.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures.
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
The Units are listed and traded on the New York Stock Exchange under the symbol “SBR.”
At February 21, 2025, there were 14,579,345 Units outstanding and approximately 853 Unit holders of record.
The Trust does not maintain any equity compensation plans.
The Trust did not repurchase any Units during the period covered by this report.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.
Liquidity and Capital Resources
The Trust makes monthly distributions to its Unit holders of the excess of the preceding month’s revenues received over expenses incurred. Upon receipt, royalty income is invested in short-term investments until its subsequent distribution. In accordance with the Trust Agreement, the Trust’s only long-term assets consist of royalty interests in producing oil and gas properties. Although the Trust is permitted to borrow funds if necessary to continue its operations, borrowings are not anticipated in the foreseeable future. Accordingly the Trust is dependent on receipt of royalty income to generate excess cash flows utilized in making distributions. These cash flows are largely dependent on such factors as oil and gas prices and production volumes, which are influenced by many factors beyond the control of the Trust. The Trust does not undertake capital projects or make capital expenditures, and is not liable for any production costs or liabilities attributable to the Royalty Properties. As a royalty owner, the Trust does not have access to certain types of information that would be disclosed by a company with oil and gas operations. See “Item 2. Properties” for a discussion of the types of information not available to the Trust.
The amount to be distributed to Unit holders (“Monthly Income Amount”) is determined on a monthly basis. The Monthly Income Amount is an amount equal to the sum of cash received by the Trust during a monthly period (the period commencing on the day after a monthly record date and continuing through and including the next succeeding monthly record date) attributable to the Royalty Properties, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. 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 such month on or before 10 business days after the monthly record date. The Monthly Income Amount per Unit is declared by the Trust no later than 10 days prior to the monthly record date. The cash received by the Trust is primarily from purchasers of the Trust’s oil and gas production and consists of gross sales of production less applicable severance taxes.
Revenue and Expense Audit and Review
As previously disclosed, significant activity has been initiated by operators in the Haynesville Shale play in the Panola County leases. The Trustee has taken efforts to confirm that the trust receives revenue on all wells in which it has ownership. The Trustee has engaged Argent Mineral Management (“AMM”), an affiliate of the Argent Financial Group, of which the Trustee is also an affiliate, to further audit the Trust's royalty revenue. See Item 13 “Certain Relationships and Related Party Transactions, and Director Independence” for further discussion of this engagement and other related party transactions.
Results of Operations
Distributable income consists of royalty income plus interest income plus any decrease in cash reserves established by the Trustee less general and administrative expenses of the Trust less any increase in cash reserves established by the Trustee. The Trust’s royalty income represents payments received during a particular time period for oil and gas production from the Trust’s properties. Because of various factors which influence the timing of the Trust’s receipt of payments, royalty income for any particular time period will usually include payments for oil and gas produced in prior periods. The price and volume figures that follow represent the volumes and prices for which the Trust received payment during 2022, 2023 and 2024.
Royalty income during 2024 decreased approximately $10,442,000, or 11 percent, compared to 2023 royalty income, which had increased approximately $32,737,000, or 26 percent, from 2022 royalty income.
Revenues generated by sales of oil and gas decreased in 2024 from 2023 due mainly to lower oil and natural gas prices ($21.4 million) and higher operating expenses and taxes ($0.5 million), partially offset by an increase in both oil and natural gas production ($11.5 million).
Gas volumes increased from 11,819,167 Mcf in 2023 to 16,509,134 Mcf in 2024 after decreasing from 14,092,037 Mcf in 2022. The average price of gas received by the Trust decreased from $3.52 per Mcf in 2023 to $1.88 per Mcf in 2024 after decreasing from $5.96 per Mcf in 2022. In February 2022, Russia invaded Ukraine and the resulting uncertainty due to the war and sanctions imposed on Russia drove the price of natural gas up significantly, peaking in the summer of 2022. Once international markets absorbed the effects of Russia’s inability to sell gas to the European Union and other countries, the price of natural gas began to ease somewhat in the second half of 2022 and 2023. The lower gas prices continued throughout most of 2024, due mainly to warmer weather in the fall and early winter in 2024, higher inflation than in previous years, along with the uncertainty brought about by the November U.S. presidential election. Late in the year, with cold weather finally arriving in some parts of the United States, natural gas prices began to increase.
Oil volumes sold increased to 815,811 barrels (“Bbls”) in 2024 from 780,930 Bbls in 2023 after increasing from 608,140 Bbls in 2022. The average sales price of oil decreased to $77.04 per Bbl in 2024, from $79.60 per Bbl in 2023 after decreasing from $90.41 per Bbl in 2022. In February 2022, Russia invaded Ukraine and the uncertainty of war and the sanctions that were imposed on Russia drove the price of oil to [near] historic levels where they peaked in June 2022, then declined through the rest of 2022 and the first few months of 2023. As 2023 went on, the price of oil increased, but the average prices were still below that of the previous year. For most of 2024, oil prices stayed lower than the prices in 2023 due mainly to higher inflation, along with the uncertainty brought about by the November U.S. presidential election.
Interest income was approximately $601,000 in 2024, which had decreased from approximately $804,000, or 25 percent, in 2023, which had increased from approximately $232,000, or 247 percent, in 2022. Changes in interest income are the result of changes in interest rates and funds available for investment.
General and administrative expenses decreased to approximately $3,528,000, or 1 percent, in 2024 from approximately $3,564,000 in 2023. This decrease was caused mainly by decreases in Escrow Agent/Trustee fees of approximately $267,000. These were offset by increases in legal and professional services of approximately $223,000 and in revenue processing of approximately $76,000.
General and administrative expenses increased to approximately $3,564,400, or 8 percent, in 2023 from approximately $3,287,400 in 2022. This increase was caused mainly by increases in Escrow Agent/Trustee fees of approximately $490,000, and in Unitholder services of approximately $155,000. These were offset somewhat by decreases in legal and professional services of approximately $178,000 and in revenue processing of approximately $181,000.
The cash received by the Trust is primarily from purchasers of the Trust’s oil and gas production and consists of gross sales of production less applicable severance taxes.
The Trust did file tax returns for 2022 and 2023 with the States of Oklahoma and New Mexico requesting refunds. The refunds represent taxes that were withheld from the proceeds of production from the Royalty Properties and remitted to the State of Oklahoma and the State of New Mexico by the applicable payors of such proceeds. [The Trust will file tax returns for 2024 with the States of Oklahoma and New Mexico requesting refunds.] The Trust has historically obtained refunds from the states of New Mexico and Oklahoma and distributed such refunds to Unit holders. However, with respect to Oklahoma, beginning in 2018, the Trust’s refund claims have been denied, and the Trust may not qualify for an exemption from withholding. The Trustee is actively working with the Oklahoma Tax Commission to resolve the issue. Unless the Trust is eligible to obtain an exemption from Oklahoma withholding tax or obtain a refund of Oklahoma withholding tax, Unit holders subject to Oklahoma income tax would be required to file an Oklahoma income tax return in order to claim a credit or refund for any Oklahoma withholding tax attributable to such Unit holder’s Units. A Unit holder’s entitlement to such a credit or refund will be dependent upon the relevant facts and circumstances of such Unit holder.
Critical Accounting Policies and Estimates
The Trust’s financial statements reflect the selection and application of accounting policies that require the Trust to make significant estimates and assumptions. The following are some of the more critical judgment areas in the application of accounting policies that currently affect the Trust’s financial condition and results of operations.
1. Basis of Accounting
The financial statements of the Trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with accounting principles generally accepted in the United States of America:
•Royalty income, net of severance and ad valorem taxes, and interest income are recognized in the month in which amounts are received by either the escrow agent or the Trust, pending verification of ownership and title.
•Trust expenses, consisting principally of routine general and administrative costs, include payments made during the accounting period. Expenses are accrued to the extent of amounts that become payable on the next monthly record date following the end of the accounting period. Reserves for liabilities that are contingent or uncertain in amount may also be established if considered necessary.
•Royalties that are producing properties are amortized using the unit-of-production method. This amortization is shown as a reduction of Trust corpus.
•Distributions to Unit holders are recognized when declared by the Trustee.
The financial statements of the Trust differ from financial statements prepared in conformity with accounting principles generally accepted in the United States of America because of the following:
•Royalty income is recognized in the month received, pending verification of ownership and title, rather than in the month of production.
•Expenses other than those expected to be paid on the following monthly record date are not accrued.
•Amortization of the royalties is shown as a reduction to Trust corpus and not as a charge to operating results.
•Reserves may be established for contingencies that would not be recorded under accounting principles generally accepted in the United States of America.
This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
2. Revenue Recognition
Revenues from royalty interests are recognized in the period in which amounts are received and verified by the Trust or escrow agent. Royalty income received by the Trust or escrow agent in a given calendar year will generally reflect the proceeds, on an entitlements basis, from natural gas produced for the twelve-month period ended September 30th in that calendar year and from oil produced for the twelve-month period ended October 31st in the same calendar year.
3. Reserve Disclosure
The SEC and the Financial Accounting Standards Board requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the twelve-month period prior to the fiscal year-end, 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. Future price changes are only considered to the extent provided by contractual arrangements in existence at year end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and gas reserves. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and the timing of development of non-producing reserves. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates. See Part II Item 8 “Financial Statements - Notes to Financial Statements - Note 8 Supplemental Oil and Gas Information (Unaudited)” for additional 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.
4. Contingencies
Contingencies related to the Royalty Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future royalty income payments to the Trust with corresponding reductions to cash distributions to Unit holders. The Trustee is aware of no such items as of December 31, 2024.
New Accounting Pronouncements
There are no new pronouncements that are expected to have a significant impact on the Trust’s financial statements.
Off-Balance Sheet Arrangements
As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and the Trustee does not have any control over or any responsibility relating to the operation of the Royalty Properties. The Trustee has powers to collect and distribute proceeds received by the Trust and to pay Trust liabilities and expenses, and its actions have been limited to those activities. Therefore, the Trust has not engaged in any off-balance sheet arrangements.
Inflation
Prices obtained for oil and gas production depend upon numerous factors that are beyond the control of the Trust, including the extent of domestic and foreign production, imports of foreign oil, market demand, domestic and worldwide economic and political conditions, storage capacity and government regulations and tax laws. Prices for both oil and gas have fluctuated between 2022 and 2024. The following table presents the weighted average prices received per year by the Trust:
Oil
Per BBL
Gas
Per Mcf
$
77.04
$
1.88
79.60
3.52
90.41
5.96
Inflationary pressures continued during 2024, which has impacted the costs of goods and services for operators of the Royalty Properties and administrative costs for the Trust.
Forward-Looking Statements
This Annual Report includes “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, which are intended to be covered by the safe harbor created thereby. All statements other than statements of historical fact included in this Annual Report are forward-looking statements. Such statements include, without limitation, factors affecting the price of oil and natural gas contained in Item 1, “Business,” certain reserve information and other statements contained in Item 2, “Properties,” certain statements regarding the Trust’s financial position, industry conditions and other matters contained in this Item 7. Although the Trustee believes that the expectations reflected in such forward-looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trustee can give no assurance that they will prove correct. There are many factors, none of which is within the Trustee’s control, that may cause such expectations not to be realized, including, among other things, factors identified in this Annual Report affecting oil and gas prices (including, without limitation, 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 or pandemics), the recoverability of reserves, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets and the factors identified in Item 1A, “Risk Factors”.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The Trust’s only long-term assets consist of royalty interests in producing oil and gas properties. As a result, the Trust is significantly exposed to fluctuations in the prices received for oil, natural gas and NGL produced and sold. The Trust is a passive entity, and other than the Trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically holds short term investments acquired with funds held by the Trust pending distribution to Unit holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unit holders to any foreign currency related market risk. The Trust invests in no derivative financial instruments and has no foreign operations or long-term debt instruments.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
Page
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 410)
Statements of Assets, Liabilities and Trust Corpus
Statements of Distributable Income
Statements of Changes in Trust Corpus
Notes to Financial Statements
All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.
Report of Independent Registered Public Accounting Firm
To the Unit Holders of
Sabine Royalty Trust and
Argent Trust Company, Trustee
Opinion on the Financial Statements
We have audited the accompanying statements of assets, liabilities and trust corpus of Sabine Royalty Trust (the Trust) as of December 31, 2024 and 2023, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities, and trust corpus of the Trust as of December 31, 2024 and 2023, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2024, in conformity with the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Trust’s internal control over financial reporting as of December 31, 2024, based on criteria established in 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 27, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Basis of Accounting
As described in Note 2 to the financial statements, these financial statements were 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 of America.
Critical Audit Matters
Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.
/s/ WEAVER AND TIDWELL, L.L.P.
We have served as the Trust’s auditor since 2016.
Houston, Texas
February 27, 2025
SABINE ROYALTY TRUST
FINANCIAL STATEMENTS
Statements of Assets, Liabilities and Trust Corpus
December 31,
Assets
Cash and short-term investments
$
9,169,742
$
9,342,423
Royalty interests in oil and gas properties less accumulated amortization of $22,314,566
(2024) and $22,299,783 (2023)
80,619
95,402
Total
$
9,250,361
$
9,437,825
Liabilities and Trust Corpus
Trust expenses payable
$
311,784
$
508,489
Other payables (Note 4)
231,645
370,430
Total liabilities
543,429
878,919
Contingencies (Note 2)
Trust Corpus (14,579,345 units of beneficial interest authorized and outstanding)
8,706,932
8,558,906
Total
$
9,250,361
$
9,437,825
The accompanying notes are an integral part of these financial statements.
Statements of Distributable Income
Year Ended December 31,
Royalty income
$
82,569,642
$
93,012,044
$
125,749,358
Interest income
601,454
803,530
231,935
Total
83,171,096
93,815,574
125,981,293
General and administrative expenses (Note 6)
3,528,402
3,564,339
3,287,420
Distributable income
$
79,642,694
$
90,251,235
$
122,693,873
Distributable income per unit (Basic and Assuming Dilution)
(14,579,345 units) (Notes 1,2)
$
5.46
$
6.19
$
8.42
The accompanying notes are an integral part of these financial statements.
Statements of Changes in Trust Corpus
Trust corpus, beginning of year
$
8,558,906
$
11,409,506
$
14,909,990
Amortization of royalty interests
(14,783
)
(17,090
)
(24,118
)
Distributable income
79,642,694
90,251,235
122,693,873
Distributions to unit holders (Note 3)
(79,479,885
)
93,084,745
(126,170,239
)
Trust corpus, end of year
$
8,706,932
$
8,558,906
$
11,409,506
Distributions per unit (Note 3)
$
5.45
$
6.38
$
8.65
The accompanying notes are an integral part of these financial statements.
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
1. Trust Organization and Provisions
Sabine Royalty Trust (the “Trust”) was established by the Sabine Corporation Royalty Trust Agreement (the “Trust Agreement”), made and entered into effective as of December 31, 1982, to receive a distribution from Sabine Corporation (“Sabine Corporation”) of royalty and mineral interests, including landowner’s royalties, overriding royalty interests, minerals (other than executive rights, bonuses and delay rentals), production payments and any other similar, nonparticipatory interest, in certain producing and proved undeveloped oil and gas properties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma and Texas (the “Royalty Properties”).
Certificates evidencing units of beneficial interest (the “Units”) in the Trust were mailed on December 31, 1982 to Sabine Corporation's shareholders of record on December 23, 1982, on the basis of one Unit for each share of Sabine’s outstanding common stock.
In May 1988, Sabine Corporation was acquired by Pacific Enterprises. Through a series of mergers, Sabine Corporation was merged into Pacific Enterprises Oil Company (USA) (“Pacific (USA)”), which in turn was merged and consolidated into Sempra Energy, effective January 1, 1993. As of August 1, 2006, Sempra Energy sold its various interests and rights to Providence Energy Corporation (“Providence”). Providence in turn transferred its interests and rights to RJ Holdings, Inc. (“RJ Holdings”) as of June 1, 2021. These transactions had no effect on the Units. RJ Holdings, Inc. as successor to Sabine Corporation, has assumed by operation of law all of Sabine Corporation’s rights and obligations with respect to the Trust. The Units are listed and traded on the New York Stock Exchange.
In connection with the transfer of the Royalty Properties to the Trust upon its formation, Sabine Corporation had reserved to itself all executive rights, including rights to execute leases and to receive bonuses and delay rentals. Through a series of mergers, Sabine Corporation was merged into Pacific (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 executive rights relating to the Royalty Properties, and the ownership of such rights by Pacific (USA) (now PEC Minerals, LP (“PEC”)) was not affected by the sale. The Trustee currently reviews all leases executed on the Trust’s behalf.
The wells on the properties conveyed to the Trust are operated by many companies including large, established companies such as BP Amoco, Chevron, ConocoPhillips and ExxonMobil. The Trustee believes these operators utilize the recovery methods best suited for the particular formations on which the properties are located.
Argent Trust Company (the “Trustee”), acts as trustee of the Trust. The terms of the Trust Agreement provide, among other things, that:
•The Trust shall not engage in any business or commercial activity of any kind or acquire assets other than those initially transferred to the Trust.
•The Trustee may not sell all or any part of its assets unless approved by the holders of a majority of the outstanding Units in which case the sale must be for cash and the proceeds, after satisfying all existing liabilities, promptly distributed to Unit holders.
•The Trustee may 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 will use reasonable efforts to cause the Trust and the Unit holders to recognize income and expenses on monthly record dates.
•The Trustee is authorized to borrow funds to pay liabilities of the Trust provided that such borrowings are repaid in full before any further distributions are made to Unit holders.
•The Trustee will make monthly cash distributions to Unit holders of record on the monthly record date (see Note 3).
On January 9, 2014, Bank of America, N.A. (as successor to InterFirst Bank Dallas, N.A.) gave notice to Unit holders that it was resigning as the Trustee subject to certain conditions including the appointment of Southwest Bank as trustee of the Trust. At a special meeting of Trust Unit holders, the Unit holders approved the appointment of Southwest Bank as successor trustee of the Trust, once Bank of America, N.A.’s resignation took effect. The effective date of Bank of America, N.A.’s resignation and the effective date of Southwest Bank’s appointment as successor trustee was May 30, 2014. Effective October 19, 2017, Simmons First National Corporation (“SFNC”) completed its acquisition of First Texas BHC, Inc., the parent company of Southwest Bank. SFNC is the parent of Simmons Bank. SFNC merged Southwest Bank with Simmons Bank effective February 20, 2018.
On November 4, 2021, Simmons Bank, as Trustee, announced that it had entered into an agreement with Argent Trust Company (“Argent”), pursuant to which Simmons Bank would resign as trustee of the Trust and would nominate Argent as successor trustee of the Trust. At a special meeting of Trust Unit holders, the Unit holders approved the appointment of Argent as successor trustee of the Trust. Simmons Bank’s resignation as trustee, and Argent’s appointment as successor trustee, became effective December 30, 2022.
The defined term “Trustee” as used herein shall refer to Bank of America, N.A. for periods prior to May 30, 2014, shall refer to Southwest Bank for periods from May 30, 2014 through February 19, 2018, shall refer to Simmons Bank for periods from February 20, 2018 through December 29, 2022, and shall refer to Argent for periods on and after December 30, 2022.
Because of the passive nature of the Trust and the restrictions and limitations on the powers and activities of the Trustee contained in the Trust Agreement, the Trustee does not consider any of the officers and employees of the Trustee to be “officers” or “executive officers” of the Trust as such terms are defined under applicable rules and regulations adopted under the Securities Exchange Act of 1934.
The proceeds of production from the Royalty Properties are receivable from hundreds of separate payors. In order to facilitate creation of the Trust and to avoid the administrative expense and inconvenience of daily reporting to Unit holders, 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 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 and a Louisiana bank in the capacities of escrow agent and of trustee under the name of Sabine Louisiana Royalty Trust. Sabine Louisiana Royalty Trust, the sole beneficiary of which is the Trust, was established 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 Louisiana. Argent now serves as Trustee of the Sabine Louisiana Royalty Trust. Therefore, 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 properties by Sabine Corporation, 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 agreement is recognized for federal income tax purposes and that the Trustee, as escrow agent is able to control the timing of income and expenses, as stated above, cash and accrual basis Unit holders should be treated as realizing income only on each monthly record date. The Trustee is treating the escrow agreement as effective for tax purposes. However, for financial reporting purposes, royalty and interest income are recorded in the calendar month in which the amounts are received by either the escrow agent or the Trust.
Distributable income as determined for financial reporting purposes for a given quarter will not usually equal the sum of distributions made during that quarter. Rather, distributable income for a given quarter will approximate the sum of the distributions made during the last two months of such quarter and the first month of the next quarter.
2. Accounting Policies
Basis of Accounting
The financial statements of the Trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with accounting principles generally accepted in the United States of America:
•Royalty income, net of severance and ad valorem taxes, and interest income are recognized in the month in which amounts are received by either the escrow agent or the Trust, pending verification of ownership and title (see Note 1).
•Trust expenses, consisting principally of routine general and administrative costs, include payments made during the accounting period. Expenses are accrued to the extent of amounts that become payable on the next monthly record date following the end of the accounting period. Reserves for liabilities that are contingent or uncertain in amount may also be established if considered necessary.
•Royalties that are producing properties are amortized using the unit-of-production method. This amortization is shown as a reduction of Trust corpus.
•Distributions to Unit holders are recognized when declared by the Trustee (see Note 3).
The financial statements of the Trust differ from financial statements prepared in conformity with accounting principles generally accepted in the United States of America because of the following:
•Royalty income is recognized in the month received, pending verification of ownership and title, rather than in the month of production.
•Expenses other than those expected to be paid on the following monthly record date are not accrued.
•Amortization of the royalties is shown as a reduction to Trust corpus and not as a charge to operating results.
•Reserves may be established for contingencies that would not be recorded under accounting principles generally accepted in the United States of America.
This comprehensive basis of accounting other than accounting principles generally accepted in the United States of America corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
Revenue Recognition
Revenues from royalty interests are recognized in the period in which amounts are received and verified by the Trust or escrow agent. Royalty income received by the Trust or escrow agent in a given calendar year will generally reflect the proceeds, on an entitlements basis, from natural gas produced for the twelve-month period ended September 30th in that calendar year and from oil produced for the twelve-month period ended October 31st in the same calendar year.
Contingencies
Contingencies related to the Royalty Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future royalty income payments to the Trust with corresponding reductions to cash distributions to Unit holders. The Trustee is aware of no such items as of December 31, 2024.
Use of Estimates
The preparation of financial statements in conformity with the basis of accounting described above requires management to make estimates and assumptions that affect reported amounts of certain assets, liabilities, revenues and expenses as of and for the reporting periods. Actual results may differ from such estimates.
Impairment
The Trustee routinely reviews its royalty interests in oil and gas properties for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If an impairment event occurs and it is determined that the carrying value of the Trust’s royalty interests may not be recoverable, an impairment will be recognized as measured by the amount by which the carrying amount of the royalty interests exceeds the fair value of these assets, which would likely be measured by discounting projected cash flows. There is no impairment of the assets as of December 31, 2024.
New Accounting Pronouncements
There are no new pronouncements that are expected to have a significant impact on the Trust’s financial statements.
Distributable Income Per Unit
Basic distributable income per Unit is computed by dividing distributable income by the weighted average Units outstanding. Distributable income per Unit assuming dilution is computed by dividing distributable income by the weighted average number of Units and equivalent Units outstanding. The Trust had no equivalent Units outstanding for any period presented. Therefore, basic distributable income per Unit and distributable income per Unit assuming dilution are the same.
Federal Income Taxes
The Internal Revenue Service (the “Service”) has ruled that the Trust is classified as a grantor trust for federal income tax purposes and therefore is not subject to taxation at the trust level. The Unit holders are considered, for federal income tax purposes, to own the Trust’s income and principal as though no trust were in existence. Accordingly, no provision for federal income tax expense has been made in these financial statements. The income of the Trust will be deemed to have been received or accrued by each Unit holder at the
time such income is received or accrued by the Trust, which is on the record date following the end of each month, as discussed above in Note 1.
Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, referred to herein collectively as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. Argent, EIN 62-1437218, 3838 Oak Lawn Avenue, Suite 1720, Dallas, Texas, 75219, telephone number 1-855-588-7839, email address trustee@sbr-sabine.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.sbr-sabine.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unit holders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units, including the issuance of Service Forms 1099 and certain written tax statements. Unit holders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.
3. Distributions to Unit Holders
The amount to be distributed to Unit holders (“Monthly Income Amount”) is determined on a monthly basis. The Monthly Income Amount is an amount equal to the sum of cash received by the Trust during a monthly period (the period commencing on the day after a monthly record date and continuing through and including the next succeeding monthly record date) attributable to the Royalty Properties, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. 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 such month on or before 10 business days after the monthly record date. The Monthly Income Amount per Unit is declared by the Trust no later than 10 days prior to the monthly record date.
The cash received by the Trust is primarily from purchasers of the Trust’s oil and gas production and consists of gross sales of production less applicable severance taxes and ad valorem taxes.
The Trust did file tax returns for 2022 and 2023 with the States of Oklahoma and New Mexico requesting refunds. The refunds represent taxes that were withheld from the proceeds of production from the Royalty Properties and remitted to the State of Oklahoma and the State of New Mexico by the applicable payors of such proceeds. The Trust will file tax returns for 2024 with the States of Oklahoma and New Mexico requesting refunds. The Trust has historically obtained refunds from the States of Oklahoma and New Mexico and distributed such refunds to Unit holders. However, with respect to Oklahoma, beginning in 2018, the Trust’s refund claims have been denied, and the Trust may not qualify for an exemption from withholding. The Trustee is actively working with the Oklahoma Tax Commission to resolve the issue. Unless the Trust is eligible to obtain an exemption from Oklahoma withholding tax or obtain a refund of Oklahoma withholding tax, Unit holders subject to Oklahoma income tax would be required to file an Oklahoma income tax return in order to claim a credit or refund for any Oklahoma withholding tax attributable to such Unit holder’s Units. A Unit holder’s entitlement to such a credit or refund will be dependent upon the relevant facts and circumstances of such Unit holder.
4. Other Payables
Other payables consist of the following at December 31:
December 31,
Royalty receipts in suspense pending verification of
ownership interest or title
$
231,645
$
370,430
The Trustee believes that these amounts represent an ordinary operating condition of the Trust and that they will be paid or released in the normal course of business.
5. Subsequent Events
Distributions
Subsequent to December 31, 2024, the Trust declared the following distributions:
Notification Date
Monthly Record
Date
Payment Date
Distribution per
Unit
January 3, 2025
January 15, 2025
January 29, 2025
$
0.448330
February 7, 2025
February 18, 2025
February 28, 2025
$
0.439510
6. General and Administrative Expenses
General and administrative expenses for the years ended December 31, were as follows:
Trustee’s fee
$
478,878
$
545,594
$
422,011
Escrow agent fee paid to Trustee
1,436,631
1,636,786
1,266,038
Professional fees
850,616
614,481
792,277
Unit holders’ services fees
579,183
634,185
395,359
Other
183,094
133,293
411,735
Total General and Administrative Expenses
3,528,402
3,564,339
3,287,420
7. Quarterly Financial Data (Unaudited)
The following table sets forth the royalty income, distributable income and distributable income per Unit of the Trust for each quarter in the years ended December 31, 2024 and 2023 (in thousands, except per Unit amounts):
Royalty
Income
Distributable
Income
Distributable
Income per Unit
First Quarter
$
20,759
$
19,921
$
1.37
Second Quarter
22,607
22,079
1.51
Third Quarter
19,784
19,070
1.31
Fourth Quarter
19,419
18,572
1.27
$
82,569
$
79,642
$
5.46
Royalty
Income
Distributable
Income
Distributable
Income per
Unit
First Quarter
$
27,135
$
26,277
$
1.80
Second Quarter
17,434
16,699
1.15
Third Quarter
14,365
13,727
0.94
Fourth Quarter
34,078
33,548
2.30
$
93,012
$
90,251
$
6.19
8. Supplemental Oil and Gas Information (Unaudited)
Reserve Quantities
Information regarding estimates of the proved oil and gas reserves attributable to the Trust are based on reports prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants. Estimates were prepared in accordance with the guidelines established by the FASB and the Securities and Exchange Commission. Certain information required by this guidance is not presented because that information is not applicable to the Trust due to its passive nature.
Oil and gas reserve quantities (all located in the United States) are estimates based on information available at the time of their preparation. Such estimates are subject to change as additional information becomes available. Reserves actually recovered, and the timing of the production of those reserves, may differ substantially from original estimates. The following schedule presents changes in the Trust’s total proved reserves (in thousands):
Oil
(Barrels)
Gas
(Mcf)
BOE*
January 1, 2022
6,020
42,749
13,145
Revisions of previous statements
14,270
2,755
Production
(438
)
(9,635
)
(2,044
)
December 31, 2022
5,959
47,384
13,856
Revisions of previous statements
2,423
7,939
3,746
Production
(467
)
(8,924
)
(1,954
)
December 31, 2023
7,915
46,399
15,648
Revisions of previous statements
1,563
34,255
7,272
Production
(606
)
(16,148
)
(3,342
)
December 31, 2024
8,872
64,236
19,578
*Barrel of Oil Equivalent
Estimated quantities of proved developed reserves of oil and gas as of the dates indicated were as follows (in thousands):
Oil
(Barrels)
NGLs
(Barrels)
Gas
(Mcf)
BOE*
Proved Developed Reserves:
January 1, 2022
4,802
1,219
42,749
13,146
December 31, 2022
4,660
1,300
47,384
13,857
December 31, 2023
5,314
2,601
46,399
15,648
December 31, 2024
6,359
2,513
64,236
19,578
Disclosure of a Standardized Measure of Discounted Future Net Cash Flows
The following is a summary of a standardized measure (in thousands) of discounted future net cash flows related to the Trust’s total proved oil and gas reserve quantities. Information presented is based upon a valuation of proved reserves by using discounted cash flows based upon average reference oil and gas prices ($76.32 per Bbl and $2.13 per MMBtu, respectively) during the twelve-month period prior to the fiscal year-end, 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 and severance and ad valorem taxes, if any, and economic conditions, discounted at the required rate of 10%. As the Trust is not subject to taxation at the trust level, no provision for income taxes has been made in the following disclosure.
Based on oil and gas product quality and property location, prices received by the Trust were slightly different than the reference prices above resulting in volume weighted average prices attributable to its proved reserves over the lives of the properties of $72.91 per Bbl of oil, $18.53 per Bbl of NGL, and $1.795 per Mcf of gas.
The impact of changes in current prices on reserves could vary significantly from year to year. Accordingly, the information presented below should not be viewed as an estimate of the fair market value of the Trust’s oil and gas properties nor should it be viewed as indicative of any trends.
December 31,
Future net cash inflows
$
549,340
$
524,282
$
657,947
Discount of future net cash flows @ 10%
(269,015
)
(226,732
)
(330,798
)
Standardized measure of discounted future net cash inflows
$
280,325
$
257,550
$
327,149
The change in the standardized measure of discounted future net cash inflows for the years ended December 31, 2024, 2023 and 2022 is as follows (in thousands):
Standardized measure of discounted future net cash flows,
January 1,
$
257,550
$
327,149
$
207,073
Royalty income, net of severance and ad valorem taxes
(82,570
)
(93,012
)
(125,749
)
Changes in prices, net of related costs
(25,194
)
(121,929
)
118,200
Revisions of previous estimates and other
104,784
112,627
106,918
Accretion of discount
25,755
32,715
20,707
Standardized measure of discounted future net cash flows,
December 31,
$
280,325
$
257,550
$
327,149
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 18, 2025, NYMEX posted oil prices were approximately $72.21 per barrel, which compared to the average posted price of $72.91 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 18, 2025, NYMEX posted gas prices were $6.40 per million British thermal units. The use of such price, as compared to the average posted price of $1.795 per million British thermal units, used to calculate the future net revenue for the Trust’s proved developed reserves would result in an increase in the standardized measure of discounted future net cash flows for gas.
9. State Taxes
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 location of the principal place of business of the Trust, which is Texas.
Because the Trust distributes all of its net income to Unit holders, it should not be subject to income tax in Louisiana, Florida, Mississippi, New Mexico or Oklahoma. While the Trust should not owe tax, Unit holders may have a state filing responsibility in each of those states.
Unit holders should consult their own tax advisor regarding state tax requirements, if any, applicable to ownership of Trust Units.
*****

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
The Trustee conducted an evaluation of the Trust’s disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, the Trustee has concluded that the Trust’s disclosure controls and procedures were effective as of the end of the period covered by this annual report.
Changes in Internal Control Over Financial Reporting
There has not been any change in the Trust’s internal control over financial reporting during the fourth quarter of 2024 that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.
Trustee’s Report on Internal Control Over Financial Reporting
The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with the modified cash basis of accounting. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control - Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control - Integrated Framework 2013, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2024.
The independent registered public accounting firm of Weaver and Tidwell, L.L.P., as auditors of the statements of assets, liabilities and trust corpus, and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2024, has issued an attestation report on the Trust’s internal control over financial reporting as of December 31, 2024, which is included herein.
Report of Independent Registered Public Accounting Firm
To the Unit Holders of
Sabine Royalty Trust and
Argent Trust Company, Trustee
Opinion on Internal Control Over Financial Reporting
We have audited Sabine Royalty Trust (the Trust)’s internal control over financial reporting as of December 31, 2024 based on criteria established in 2013 Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the statements of assets, liabilities, and trust corpus of Sabine Royalty Trust as of December 31, 2024 and 2023 and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2024, and our report dated February 27, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
The Trustee is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustee’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Trust’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sabine Royalty Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting described in Note 2 to the financial statements. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis of accounting described in Note 2 to the financial statements, and that receipts and expenditures of the entity are being made only in accordance with authorizations of the Trustee and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ WEAVER AND TIDWELL, L.L.P.
Houston, Texas
February 27, 2025

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information.
The Trust does not have any directors or officers, and as a result, no such person adopted or terminated any Rule 10b5-1 trading arrangement or any non-Rule 10b5-1 trading arrangement, as defined in Item 408(a) of Regulation S-K, during the most recent fiscal quarter.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors and Executive Officers and Corporate Governance.
Directors and Executive Officers. The Registrant has no directors or executive officers. The Trustee is a corporate trustee which may be removed, with or without cause, by the affirmative vote at a meeting duly called and held of the holders of a majority of the Units represented at the meeting.
Compliance with Section 16(a) of the Exchange Act. The Trust has no directors and officers and knows of no Unit holder that is a beneficial owner of more than ten percent of the outstanding Units, and is therefore unaware of any person that failed to report on a timely basis reports required by Section 16(a) of the Securities Exchange Act of 1934, as amended.
Code of ethics. Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee, Argent Trust Company, must comply with the company’s code of ethics which may be found in the employee handbook.
Audit Committee. The Trust has no directors and therefore has no audit committee or audit committee financial expert.
Nominating Committee. The Trust has no directors and therefore has no nominating committee.
Insider Trading Policy. Because the Trust does not have officers, directors, or employees, it has not adopted insider trading policies and procedures governing the purchase, sale and/or other disposition of Trust securities by such persons.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation.
(a)Compensation Committee Interlocks and Insider Participation/Compensation Committee Report. The Trust has no officers or directors and is administered by a trustee. The Trust does not have a compensation committee or maintain any equity compensation plans and there are no units reserved for issuance under any such plans.
(b)Compensation of the Trustee. See the Special Statement of Fees and Expenses Paid by Sabine Royalty Trust to Argent Trust Company as Trustee and Escrow Agent attached as Exhibit 99 hereto for information regarding the fees earned by Argent Trust Company as Trustee and Escrow Agent. Please see Item 13. Certain Relationships and Related Transactions, and Director Independence for information on the revenue audit that is being conducted by Argent Mineral Management (“AMM”), an affiliate of Argent Financial, of which the Trustee is also an affiliate.
(c)Pay Ratio Disclosure. The Trust does not have a principal executive officer or employees and therefore, the pay ratio disclosure and other executive compensation information is not applicable.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
(a)Security Ownership of Certain Beneficial Owners. Based on the Trustee’s review of information filed with the SEC as of February 27, 2024, the following table sets forth information with respect to each person known to the Trustee to beneficially own more than 5% of the outstanding Units:
Name and Address
Amount
and Nature
of Beneficial
Ownership
Percent
of Class
Christopher B. Sarofim
Two Houston Center, Suite 2907
909 Fannin Street
Houston, TX 77010
809,705(1)
5.6
%
(1)Pursuant to a Schedule 13G/A filed February 28, 2024, Christopher B. Sarofim reported as of December 31, 2023, he directly and through certain entities of which he is a controlling person beneficially owned 787,605 Units, of which he had sole voting and dispositive power with respect to 539,407 Units and shared voting and dispositive power with respect to 248,198 Units.
(b)Security Ownership of Management. The Trust has no directors or executive officers. Argent Trust Company, the Trustee, held as of December 31, 2024 an aggregate of 13,177 Units in various fiduciary capacities, and it had shared voting and investment power with respect to 12,693 of such Units.
(c)Changes in Control. The Trustee knows of no arrangements the operation of which may at a subsequent date result in a change in control of the Registrant.
(d)Securities Authorized for Issuance Under Equity Compensation Plans. The Trust has no equity compensation plans.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence.
See Item 11. “Executive Compensation”, for the remuneration received by Argent Trust Company as Trustee and Escrow Agent.
As noted in Item 10.“Directors, Executive Officers and Corporate Governance”, the Trust has no directors, executive officers, audit committee, audit committee financial expert, compensation committee or nominating committee. The Trustee is a corporate trustee which may be removed, with or without cause, by the affirmative vote at a meeting duly called and held of the holders of a majority of the units represented at the meeting.
The Trustee has engaged AMM to audit the revenue received by the Trust. This audit includes production volumes and realized prices, along with the operator deductions made and severance taxes taken from those revenues in conjunction with the leases and conveyances governing the Trust. This audit is being performed in addition to our normal review procedures to confirm that the maximum amount of royalties are received by the Trust and that recoveries of unpaid royalties are made, if warranted. From August 2024 through the end of December 2024, the Trust paid approximately $77,600 to AMM for these services. This audit is expected to be an ongoing project.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services.
Fees for services performed by Deloitte & Touche LLP and Weaver and Tidwell, L.L.P. for the years ended December 31, 2024 and 2023 are:
Audit fees-Weaver and Tidwell, L.L.P.
$
136,100
$
157,000
Audit-related fees: Weaver and Tidwell, L.L.P.
$
-
$
-
Tax fees: Deloitte & Touche LLP
$
55,134
$
44,968
All other fees(1)
$
35,700
$
15,487
(1)FORVIS (formerly BKD) was the firm engaged to audit the “Statement of Fees and Expenses Paid by Sabine Royalty Trust to Argent Trust Company, as “Trustee and Escrow Agent” report, as per the Trust Agreement, which is filed as Exhibit 99 to this Form 10-K.
As referenced in Item 10, above, the Trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to Deloitte & Touche LLP or Weaver and Tidwell, L.L.P.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules.
(a)The following documents are filed as a part of this report:
1.Financial Statements (included in Item 8 of this report)
Reports of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus at December 31, 2024 and 2023
Statements of Distributable Income for Each of the Three Years in the Period Ended December 31, 2024
Statements of Changes in Trust Corpus for Each of the Three Years in the Period Ended December 31, 2024
Notes to Financial Statements
2.Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the financial statements and notes thereto.
3.Exhibits
(4)(a)
-
Sabine Corporation Amended and Restated Royalty Trust Agreement effective as of May 22, 2014 (incorporated by reference to Exhibit 4(a) of the Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
(b)
-
Amendment No. 1 to the Amended and Restated Royalty Trust Agreement of Sabine Royalty Trust, dated May 2, 2022 (incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed May 6, 2022).
(c)*
-
Sabine Corporation Louisiana Royalty Trust Agreement effective as of December 31, 1982, by and between Sabine Corporation and Hibernia National Bank in New Orleans, as trustee, and joined in by InterFirst Bank Dallas, N.A., as trustee. (P)
(23)**
-
Consent of DeGolyer and MacNaughton.
(31)**
-
Rule 13a-14(a)(15d-14(a)) Certification.
(32)**
-
Certification by Argent, Trustee of Sabine Royalty Trust, dated February 27, 2025 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
(97)**
-
Executive Officer Compensation Recovery Policy
(99)**
-
Report dated February 27, 2025 of the Special Purpose Statement of Fees and Expenses paid by Sabine Royalty Trust to Argent Trust Company, as Trustee and Escrow Agent.
*	Exhibit 4(c) is incorporated herein by reference to Exhibit 4(b), respectively, of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1993.
**	Filed herewith.
(P)Paper exhibits.