MESA ROYALTY TRUST/TX

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PART I

Item 1.

Business.

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DESCRIPTION OF THE TRUST

The Trust, created under the laws of the State of Texas, maintains its offices at the office of the Trustee, The Bank of New York Mellon Trust Company, N.A., (the “Trustee”), 601 Travis Street, Floor 16, Houston, Texas 77002. The telephone number of the Trust is 713-483-6020. The Trust has no employees. Administrative functions of the Trust are performed by the Trustee. The Trustee maintains a website for the Trust that makes available, free of charge, filings by the Trust with the SEC and other information. Any reports filed with the SEC are accessible free of charge through the Trust’s website as soon as reasonably practicable after the Trustee electronically files such material with, or furnishes it to, the SEC. The Trust’s website is http://mtr.q4web.com/home/default.aspx. Information contained on, or that can be accessed through the Trust’s website, is not incorporated by reference into this Form 10-K, and you should not consider information on the Trust’s website to be part of this Form 10-K. The SEC maintains a website at www.sec.gov that contains reports and other information regarding SEC registrants, including the Trust.

Trust Corpus Description. The Mesa Royalty Trust (the “Trust”) was created on November 1, 1979, and is now governed by the Mesa Royalty Trust Indenture (as amended, the “Trust Indenture”). Through a series of conveyances, assignments, and acquisitions, the Trust currently owns an overriding royalty interest (the “Royalty”) equal to 11.44% of 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interest in certain producing oil and gas properties located in the:

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San Juan Basin field of New Mexico (the “San Juan Basin — New Mexico Properties”); and

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San Juan Basin field of Colorado (the “San Juan Basin — Colorado Properties”, and together with the “San Juan Basin — New Mexico Properties, the “San Juan Basin Royalty Properties”, and together with the Hugoton Royalty Properties, the “Royalty Properties”).

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Trust Corpus Conveyance History. On November 1, 1979, Mesa Petroleum Co., predecessor to Mesa Limited Partnership (“MLP”), which was the predecessor to MESA Inc., conveyed to the Trust the Royalty equal to 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interests in properties conveyed by the assignor on that date (the “Subject Interests”). The Subject Interests consisted of interests in the Royalty Properties described above. The Royalty is evidenced by counterparts of an Overriding Royalty Conveyance, dated as of November 1, 1979 (the “Conveyance”). In 1985, the Trust Indenture was amended and the Trust conveyed to an affiliate of Mesa Petroleum Co. 88.5571% of the original Royalty (such transfer, the “1985 Assignment”). The effect of the 1985 Assignment was an overall reduction of approximately 88.56% in the size of the Trust. As a result, the Trust is now entitled to receive 11.44% of 90% of the Net Proceeds attributable to each month.

Hugoton Royalty Properties. On November 22, 2019, Riviera Resources, Inc. completed the sale of its interest in its remaining properties located in the Hugoton Basin to Scout Energy Group V, LP (“Scout”). Since November 23, 2019, Scout has operated the Hugoton Royalty Properties.

San Juan Basin — Colorado Properties. The Trust’s interest in the San Juan Basin Royalty Properties was conveyed from a working interest in 31,328 net producing acres in northwestern New Mexico and southwestern Colorado. ConocoPhillips sold the portion of its interests in the San Juan Basin — Colorado Properties to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow Production Company (“Red Willow”) (effective April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its interest in the San Juan Basin — Colorado Properties to BP Amoco Company (“BP”), a subsidiary of BP p.l.c. On February 28, 2020, BP completed the sale of all of its interest in the San Juan Basin — Colorado Properties to SIMCOE LLC (“Simcoe”), an affiliate of IKAV Energy Inc. BP, under a transition services agreement with Simcoe, operated the properties until December 1, 2020. On September 16, 2025, Mach Natural Resources LP (Mach) completed the purchase of all membership interests of Simcoe, which included the interest in the San Juan — Colorado Properties. . Simcoe, now a subsidiary of Mach, and Red Willow currently operate the San Juan Basin — Colorado Properties.

San Juan Basin — New Mexico Properties. Starting from the date of the San Juan Basin Sale and ending on July 31, 2017, ConocoPhillips operated substantially all of the San Juan Basin — New Mexico Properties, except a small number of properties that had been assigned to XTO Energy, Inc. (“XTO”) effective January 1, 2005. On July 31, 2017, ConocoPhillips sold its San Juan Basin assets to Hilcorp San Juan LP (“Hilcorp”), an affiliate of Hilcorp Energy Company. On March 29, 2018, XTO sold to Hilcorp its interests in the San Juan Basin — New Mexico Properties. Hilcorp currently operates all of the San Juan Basin — New Mexico Properties.

As used in this report, Scout refers to the current operator of the Hugoton Royalty Properties, Hilcorp refers to the current operator of the San Juan Basin — New Mexico Properties, and Simcoe and Red Willow refer to the current co-operators of certain tracts of land included in the San Juan Basin — Colorado Properties, unless otherwise indicated. Scout, Mach, Red Willow and Hilcorp are each individually referred to herein as “Working Interest Owner” or collectively as the “Working Interest Owners.”

The Royalty Properties are required to be operated by the Working Interest Owners in accordance with reasonable and prudent business judgment and good oil and gas field practices. Each Working Interest Owner has the right to abandon any well or lease if, in its opinion, such well or lease ceases to produce or is not capable of producing oil, gas or other minerals in commercial quantities. Each Working Interest Owner markets the production on terms determined by it under the circumstances. See “Contracts”. The Trustee has no power or authority to exercise any control over the operation of the Royalty Properties or the marketing of production therefrom. In addition, the Trust does not undertake or control any capital projects or capital expenditures related to any of the Royalty Properties.

Trustee and Terms of Trust Indenture. The Trust is a passive entity whose purposes are limited to: (1) converting the Royalty to cash, either by retaining it and collecting the proceeds of production (until production has ceased or the Royalty is otherwise terminated) or by selling or otherwise disposing of the Royalty and (2) distributing such cash, net of amounts for payments of liabilities to the Trust, to the unitholders. The Trust has no sources of liquidity or capital resources other than the revenues, if any, attributable to the Royalties and interest on cash held by the Trustee as a reserve for liabilities or for distribution. The terms of the Trust, the Trust Indenture and agreements with the Working Interest Owners provide, among other things, that:

(a) the Trust cannot engage in any business or investment activity or purchase any assets;

(b) the Royalty can be sold in part or in total for cash upon approval by the unitholders;

(c) the Trustee can establish cash reserves, place cash reserves in interest bearing accounts or certificates, and borrow funds to pay liabilities of the Trust and can pledge assets of the Trust to secure payment of the borrowings;

(d) the Trustee will make cash distributions to the unitholders in January, April, July and October each year as discussed more fully in Note 2 of the Notes to Financial Statements contained in Item 8 of this Form 10-K;

(e) the Trust will terminate upon the first to occur of the following events: (i) at such time as the Trust’s Royalty income for two successive years is less than $250,000 per year or (ii) a vote by the unitholders in favor of termination. Upon termination of the Trust, the Trustee will sell for cash all the assets held in the Trust estate and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied; and

(f) Scout, Hilcorp and Simcoe, now a subsidiary of Mach, will reimburse the Trust for 59.34%, 27.45% and 1.77%, respectively, for general and administrative expenses of the Trust.

Discussion of Net Proceeds. The Conveyance provides for a monthly computation of Net Proceeds. Net Proceeds is defined in the Conveyance as the “Gross Proceeds” received by the Working Interest Owners during a particular period, minus certain production and capital costs for such period. “Gross Proceeds” is defined in the Conveyance as the amount received by the Working Interest Owners from the sale of “Subject

Minerals”, subject to certain adjustments. “Subject Minerals” means all oil, gas and other minerals, whether similar or dissimilar, in and under, and which may be produced, saved and sold from, and which accrue and are attributable to, the Subject Interests from and after November 1, 1979. “Production costs” means, generally, costs incurred on an accrual basis by the Working Interest Owners in operating the Royalty Properties, including capital and non-capital costs. If production and capital costs exceed Gross Proceeds for any month, the excess, plus interest thereon at 120% of the prime rate of Bank of America, is recovered out of future Gross Proceeds prior to the making of further payment to the Trust. The Trust, however, is generally not liable for any operating costs or other costs or liabilities attributable to the Royalty Properties or minerals produced therefrom. The Trust is not obligated to return any Royalty income received in any period.

The Working Interest Owners are required to maintain books and records sufficient to determine the amounts payable under the Royalty. Additionally, in the event of a controversy between a Working Interest Owner and any purchaser as to the correct sales price for any production, amounts received by such Working Interest Owner and promptly deposited by it with an escrow agent are not considered to have been received by such Working Interest Owner, and, therefore, are not subject to being payable with respect to the Royalty until the controversy is resolved; but all amounts thereafter paid to such Working Interest Owner by the escrow agent will be considered amounts received from the sale of production. Similarly, operating costs include any amounts a Working Interest Owner is required to pay whether as a refund, interest or penalty to any purchaser because the amount initially received by such Working Interest Owner as the sales price was in excess of that permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation. Within 30 days following the close of each calendar quarter, the Working Interest Owners are required to deliver to the Trustee a statement of the computation of Net Proceeds attributable to such quarter.

The brief discussions of the Trust Indenture and the Conveyance contained herein are qualified in their entirety by reference to the Trust Indenture and the Conveyance themselves, which are exhibits to this Form 10-K and are available upon request from the Trustee.

DESCRIPTION OF THE UNITS

Each unit of beneficial interest is evidenced by a transferable certificate issued by the Trustee or book-entry notation maintained by the Trust’s transfer agent. Each unit ranks equally for purposes of distributions and has one vote on any matter submitted to unitholders. A total of 1,863,590 units were outstanding at March 24, 2026.

Distributions

The Trustee determines for each month the amount of cash available for distribution to unitholders for such month (the “Monthly Distribution Amount”), which consists of the cash received from the Royalty during such month, minus the obligations of the Trust paid during such month as adjusted for changes during such month in any cash reserves established for the payment of contingent or future obligations of the Trust made by the Trustee. The Monthly Distribution Amount for each month is payable to unitholders of record on the monthly record date, which is the close of business on the last business day of such month or such other date as the Trustee determines is required to comply with legal or stock exchange requirements. However, pursuant to the Trust Indenture and in order to reduce the administrative expenses of the Trust, the Trustee does not distribute cash monthly. Instead, the Trustee makes distributions, if any, during January, April, July and October of each year. While distributions are scheduled to be made four times per calendar year, the Trustee distributes to each person who was a unitholder of record on one or more of the immediately preceding three monthly record dates, an amount equal to the Monthly Distribution Amount for the month or months that such holder was a unitholder of record plus interest earned on such Monthly Distribution Amount from the Monthly Record Date to the payment date. Under the terms of the Trust Indenture, interest is earned at a rate of 1.5% below the greater of (i) the prime rate charged by The Bank of New York Mellon Trust Company, N.A. or (ii) the interest rate which The Bank of New York Mellon Trust Company, N.A. pays in the normal course of business on amounts placed with it. Interest income may vary significantly across different payment dates.

The Working Interest Owners reimburse the Trust for portions of the total expenses incurred each month. The portions of expenses incurred by the Trustee without reimbursement from the Working Interest Owners are unreimbursed expenses. Unreimbursed expenses for any reporting period are included in general and administrative expenses, which results in a reduction of distributable income. As of December 31, 2025, there were $0 of unreimbursed expenses.

The terms of the Trust Indenture provide, among other things, that the Trustee may establish cash reserves and borrow funds to pay liabilities of the Trust and may pledge assets of the Trust to secure payment of the borrowings in accordance with the Trust Indenture. At any given time, the amount reserved for such future unknown contingent liabilities and expenses (the “Contingent Reserve”) is included in cash and short-term investments. Liability of Unitholders

The Trust unitholders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a corporation’s liabilities. In regard to the unitholders, the Trustee may generally be held liable for any excess liabilities incurred if the Trustee incurs any liability without ensuring that such liability will be satisfiable only out of the Trust’s assets (regardless of whether the assets are adequate to satisfy the liability) and not out of amounts distributed to, or other assets owned by, the unitholders. However, under Texas law, it is unclear whether a unitholder would be jointly and severally liable for any liability of the Trust in the event that all of the following conditions were to occur: (1) the satisfaction of such liability was not by contract limited to the assets of the Trust, (2) the assets of the Trust were insufficient to discharge such liability, and (3) the assets of the Trustee were insufficient to discharge such liability. As a result, Trust unitholders may be exposed to personal liability.

Federal Income Tax Matters

This section is a summary of federal income tax matters of general application, which addresses the material tax consequences of the ownership and sale of the Trust’s units. Except where indicated, the discussion below describes general federal income tax considerations applicable to individuals who are citizens or residents of the U.S. Accordingly, the following discussion has limited application to domestic corporations, foreign persons and persons subject to specialized federal income tax treatment, such as regulated investment companies and insurance companies. It is impractical to comment on all aspects of federal, state, local and foreign laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in the units as they relate to the particular circumstances of every unitholder. Each unitholder should consult its own tax advisor with respect to its particular circumstances.

Classification of the Trust

In a technical advice memorandum dated February 26, 1982, the National Office of the Internal Revenue Service (the “IRS”) advised the Dallas District Director that the Trust is classifiable as a grantor trust and not as an association taxable as a corporation. As a grantor trust, the Trust incurs no federal income tax liability and each unitholder is subject to tax on such unitholder’s pro rata share of the income and expense of the Trust as if such unitholder were the direct owner of a pro rata share of the Trust’s assets. In addition, there is no state tax liability for the period.

The Trustee assumes that some Trust units are held by a middleman, 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 custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. Notwithstanding the foregoing, the middlemen holding units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury Regulations (as defined below) with respect to such units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose 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 units.

Available Trust Tax Information

The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Floor 16, Houston, Texas 77002, telephone number 713-483-6020, is the representative of the Trust that will provide tax information in accordance with applicable Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. In compliance with the Treasury Regulations reporting requirements for WHFITs and the dissemination of Trust tax reporting information, the Trustee provides a tax information reporting booklet which is intended to be used only to assist Trust unitholders in the preparation of their federal income tax returns. This tax information booklet can be obtained at http://mtr.q4web.com/home/default.aspx.

This summary is based on current provisions of the Internal Revenue Code of 1986, as amended (“Code”), existing and proposed Internal Revenue Treasury Regulations (“Treasury Regulations”) thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. No assurance can be provided that the statements set forth herein (which do not bind the IRS or any court) will not be challenged by the IRS or will be sustained by any court if challenged.

Income and Depletion

Royalty income, net of depletion and severance taxes, is portfolio income. Subject to certain exceptions and transitional rules, Royalty income cannot be offset by passive losses. Additionally, interest income is portfolio income.

Generally, prior to the Revenue Reconciliation Act of 1990, the transferee of an oil and gas property could not claim percentage depletion with respect to production from the property if it was “proved” at the time of the transfer. This rule is not applicable in the case of transfers of properties after October 11, 1990. Thus, eligible unitholders who acquired units after that date are entitled to claim an allowance for percentage depletion with respect to Royalty income attributable to such units to the extent that this allowance exceeds cost depletion as computed for the applicable period.

Backup Withholding

Distributions from the Trust are generally subject to backup withholding at a current rate of 24%. Backup withholding will not normally apply to distributions to a unitholder unless the unitholder fails to properly provide to the Trust its taxpayer identification number or the IRS notifies the Trust that the taxpayer identification number provided by the unitholder is incorrect.

Sale of Units

Generally, except for recapture items, the sale, exchange or other disposition of a unit will result in capital gain or loss measured by the difference between the tax basis in the unit and the amount realized. Effective for property placed in service after December 31, 1986, the amount of gain, if any, realized upon the disposition of oil and gas property is treated as ordinary income up to the amount of intangible drilling and development costs incurred with respect to the property and depletion claimed to the extent it reduced the taxpayer’s basis in the property. Under this provision, depletion attributable to a unit acquired after 1986 will be subject to recapture as ordinary income upon disposition of the unit or upon disposition of the oil and gas property to which the depletion is attributable. The balance of any gain or any loss will be capital gain or loss if the unit was held by the unitholder as a capital asset, either long-term or short-term depending on the holding period of the unit. This capital gain or loss will be long-term if a unitholder’s holding period exceeds one year at the time of sale or exchange. Under current law, the highest marginal U.S. federal income tax rate applicable to long-term capital gains of individuals is 20%. Moreover, this rate is subject to change by new legislation at any time. The deductibility of capital losses is subject to certain limitations. Capital gain or loss will be short-term if the unit has not been held for more than one year at the time of sale or exchange.

Additional Tax on Net Investment Income

Individuals, estates, and trusts with income above certain thresholds are subject under Section 1411 of the Code to an additional 3.8% tax — also known as the Net Investment Income Tax (“NIIT”) — on their net investment income. Grantor trusts such as Mesa Royalty Trust are not subject to the NIIT; however, the unitholders may be subject to the tax. For these purposes, investment income would generally include certain income derived from investments, such as the Royalty income derived from the units and gain realized by a unitholder from a sale of the units.

Non-U.S. Unitholders

In general, a unitholder who is a nonresident alien individual or which is a foreign corporation, each a “non-U.S. unitholder” for purposes of this discussion, will be subject to tax on the gross income (without taking into account any deductions, such as depletion) produced by the Royalty at a rate equal to 30% or, if applicable, at a lower treaty rate. This tax will be withheld by the Trustee and remitted directly to the U.S. Treasury Department. A non-U.S. unitholder may elect to treat Royalty income as effectively connected with the conduct of a U.S. trade or business under provisions of the Code or pursuant to any similar provisions of applicable treaties. Upon making this election, a non-U.S. unitholder is entitled to claim all deductions with respect to that income, but he must file a U.S. federal income tax return to claim these deductions. This election once made is irrevocable unless an applicable treaty allows the election to be made annually.

The Code and the Treasury Regulations thereunder treat the publicly traded Trust as if it were a U.S. real property holding corporation. Accordingly, a non-U.S. unitholder may be subject to U.S. withholding and federal income tax on the gain on the disposition of his units if he meets certain ownership thresholds.

In addition, if a foreign corporation elects under provisions of the Code to treat Royalty income as effectively connected with the conduct of a U.S. trade or business, the corporation may also be subject to the U.S. branch profits tax at a rate of 30%. This tax is imposed on U.S. branch profits of a foreign corporation that are not reinvested in the U.S. trade or business and is in addition to the tax on effectively connected income. The branch profits tax may be either reduced or eliminated by treaty. Federal income taxation of a non-U.S. unitholder is a highly complex matter which may be affected by many considerations. Therefore, each non-U.S. unitholder is encouraged to consult with his own tax advisor with respect to its ownership of Trust units.

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 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 U.S. governing FATCA may be subject to different rules. Foreign unitholders are encouraged to consult their own tax advisors regarding the possible implications of these withholding provisions on their investment in Trust units.

Tax-exempt Organizations

The Royalty and interest income should not be “unrelated business taxable income” ​(as defined in Code § 512(b)), so long as, generally, a unitholder did not incur debt to acquire a unit or otherwise incur or maintain a debt that would not have been incurred or maintained if the unit had not been acquired. Legislative proposals have been made from time to time which, if adopted, would result in the treatment of Royalty income as unrelated business taxable income. Each tax-exempt unitholder is encouraged to consult its own advisor with respect to the treatment of Royalty income.

DESCRIPTION OF ROYALTY PROPERTIES

Producing Acreage and Wells as of December 31, 2025

Detailed information concerning the number of wells and producing acres on Royalty Properties is not generally available to the owners of royalty interests. Consequently, an accurate count of the number of wells and acreage located on the Royalty Properties cannot readily be obtained from the Working Interest Owners.

The principal property interest initially conveyed to the Trust was carved out of the working interest in 104,437 net producing acres in the Hugoton field of Kansas currently operated by Scout.

Because the Hugoton field gas is sold in the intrastate and interstate markets, it is subject to state and federal laws and regulations. The Kansas Corporation Commission is the state regulatory agency responsible for overseeing oil and gas operations in the state of Kansas. Hugoton field gas is also affected by the rules and regulations of the Federal Energy Regulatory Commission (the “FERC”). See “Regulation and Prices”.

San Juan Basin Royalty Properties

The Trust’s interest in the San Juan Basin Royalty Properties was conveyed from a working interest in 31,328 net producing acres in northwestern New Mexico and southwestern Colorado. ConocoPhillips sold the portion of its interests in the San Juan Basin — Colorado Properties to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow (effective April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its interest in the San Juan Basin — Colorado Properties to BP. On February 28, 2020, BP completed the sale of all of its interest in the San Juan Basin — Colorado Properties to Simcoe. BP, under a transition services agreement with Simcoe, operated the properties until December 1, 2020. On September 16, 2025, Mach completed the purchase of all membership interests of Simcoe, which included the interest in the San Juan Basin — Colorado Properties.

The Trust has not been informed by any of the other Working Interest Owners of any exploratory or development wells drilled on any Royalty Properties during 2025, 2024 or 2023.

Reserves

A study of the proved oil and gas reserves covering the Hugoton Royalty Properties and San Juan Basin Royalty Properties (the “Reserve Report”) and attributable to the Trust has been made by Miller and Lents, independent petroleum engineering consultants, as of December 31, 2025. A copy of this Reserve Report has been filed as Exhibit 99 to this Form 10-K. Miller and Lents restricts its activities exclusively to consultation. It does not accept contingency fees or other compensation that may be considered to be conditional upon the outcome of its studies. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. In serving the petroleum industry and financial community, the firm’s experienced staff provides knowledge, independent judgment, integrity, and confidential service to its clients. The firm is a Texas Registered Engineering Firm, No. F1442.

Production of the Reserve Report was supervised by a Senior Vice President at Miller and Lents, Ltd. who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 14 years of relevant experience in the estimation, assessment and evaluation of oil and gas reserves. She graduated from the University of Tennessee in 2011 with a degree in Mechanical Engineering.

The Reserve Report reflects estimated production, reserve quantities and future net revenue based upon estimates of the future timing of actual production without regard to when received in cash by the Trust, which differs from the manner in which the Trust recognizes and accounts for its Royalty income. Estimates of the gross and net proved reserves, as of December 31, 2025, of the Trust’s ownership in the net overriding royalty interests in the Royalty Properties are presented below. Total liquid reserves (condensate and natural gas liquids) are expressed in thousands of barrels (Mbbl) and gas reserves are expressed in millions of cubic feet (MMcf).

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(1)

Data from Red Willow was omitted in the Reserve Report, because it operates an immaterial number of wells relative to the total number of wells currently producing from the Royalty Properties. Excess production costs related to Red Willow as of December 31, 2025 are included in Net Proceeds paid to the Trust by Red Willow.

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The estimated future net revenue and standardized measure of future net Royalty income, discounted at 10 percent per annum attributable to the Trust’s Royalty as of December 31, 2025 is summarized in the table below. These estimates are provided based upon the economic assumptions furnished by the Working Interest Owners, and are expressed in thousands of dollars:

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(1)

Future income tax expenses were excluded in the preparation of these estimates.

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Please read “Summary Reserve Report from Miller and Lents” attached hereto as Exhibit 99 for more information. The information herein is qualified in its entirety by such Summary Reserve Report.

The Reserve Report was delivered to the Trustee on March 10, 2026. Net reserves attributable to the Trust are calculated from the Trust’s net revenues for each of the Working Interest Owners. To estimate net gas reserves, the Trust’s total net revenue from each of the Working Interest Owners is divided by the net value of 1 Mcf of gas. The net value of 1 Mcf of gas is the gas price per Mcf, plus the condensate value per Mcf of gas, plus the NGL value per Mcf of gas. The net condensate and NGL reserves are calculated by multiplying their respective yields by the net gas reserves. Revenue values used in the Reserve Report were estimated using the following prices: (1) oil prices — $56.18 per Bbl; (2) natural gas liquids prices — $30.16 per Bbl for the San Juan Basin-New Mexico Royalty Properties and $20.16 per Bbl for Hugoton Royalty Properties; and (3) natural gas prices — $2.97 per Mcf for San Juan Basin-New Mexico Royalty Properties, $0.81 per Mcf for San Juan Basin-Colorado Royalty Properties and $3.13 per Mcf for Hugoton Royalty Properties, with the initial prices also used as weighted average prices held constant thereafter over the lives of the properties. Estimates of operating expenses were based on current expenses and used for the life of the Royalty Properties with no increases in the future based on inflation.

Preparation of Reserve Estimates

For further information regarding the net overriding royalty interest, the Basis of Accounting and Supplemental Reserve Information (Unaudited), see Notes 1, 2 and 7, respectively, in the Notes to Financial Statements contained in Item 8 of this Form 10-K.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures, including many factors beyond the control of the producer. Reserve data included above and in these reports represents estimates only and should not be construed as being exact. The discounted present values shown by the Reserve Report should not be construed as the current market value of the estimated gas and oil reserves attributable to the Royalty Properties or the costs that would be incurred to obtain equivalent reserves, since a market value determination would include many additional factors.

The Trustee has been advised that each of the foregoing estimates were prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”). Accordingly, the estimates are based on existing economic and operating conditions in effect at December 31, 2025, with no provision for future increases or decreases except for periodic price redeterminations in accordance with existing gas contracts. Actual future prices and costs may be materially greater or less than the assumed amounts in the reserve reports. Because reserve reports are limited to proved reserves, future capital expenditures for recovery of reserves not classified as proved are not included in the calculation of estimated future net revenues. Reserve assessment is a subjective process of estimating the recovery from underground accumulations of gas and oil that cannot be measured in an exact way, and estimates of other persons might differ materially from those of Miller and Lents. Accordingly, reserve estimates are often different from the quantities of hydrocarbons that are ultimately recovered.

The Trustee relies on Miller and Lents to prepare the reserve estimates attributable to the Trust’s interests in the Royalty Properties. Although the Trustee inquires with the third-party reserve engineer about the information provided by the Working Interest Owners and the assumptions made and methodologies used by the third-party reserve engineer, the Trustee does not control the information provided by the Working Interest Owners or the assumptions made or methodologies used by the third-party reserve engineer. Accordingly, such information is outside the scope of the internal controls of the Trust and the Trustee. Any past practices not consistent with the Conveyance could also cause the basis for the reserve estimates included above to differ from actual reserve quantities and future net revenues.

Income, Production and Production Prices and Production Costs

Sales and production data from the Royalty Properties for the last two fiscal years is included in the table below. As reflected in the table, natural gas represents the vast majority of production from the Royalty Properties. Although the Trust is exposed to pricing fluctuations with respect to oil and condensate and natural gas liquids, the pricing environment of natural gas has a much more significant impact on Royalty income than any other hydrocarbon. For additional information related to the Trust’s Reserve Report, see “Note 7 — Supplemental Reserve Information (Unaudited)” in the Notes to Financial Statements contained in Item 8 of this Form 10-K.

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(1)

Average production costs attributable to the Royalty are calculated as stated capital costs plus operating costs, divided by stated net production volumes attributable to the Royalty paid. Production costs may be incurred in one operating period and then recovered in a subsequent operating period, which may cause Royalty income paid to the Trust not to agree to the Trust’s Royalty interest in the Net Proceeds.

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(2)

Net production volumes attributable to the Royalty are determined by dividing Royalty income by the average sales price received. Any differences noted are due to rounding.

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CONTRACTS

Natural gas and natural gas liquids produced by Scout from the Hugoton Royalty Properties accounted for approximately 0% of the Royalty income of the Trust for the year ended December 31, 2025. Since June 1, 1995 natural gas produced from the Hugoton field has generally been sold under short-term and multi-month contracts to multiple purchasers. Scout has advised the Trust that it expects to continue to market natural gas production from the Hugoton field under short-term and multi-month contracts. Overall average daily market prices received for natural gas from Hugoton Royalty Properties were higher for the year ended December 31, 2025 as compared to the year ended December 31, 2024. For the year ended December 31, 2025, Scout provided Process (as defined in the Conveyance) services for the Hugoton Royalty Properties, and such services are charged against the Royalty in accordance with the terms of the Conveyance.

San Juan Basin

Natural gas, oil, condensate and natural gas liquids produced from the San Juan Basin — New Mexico Royalty Properties accounted for all of the Royalty income of the Trust for the year ended December 31, 2025. In 2025, Simcoe previously informed the Trustee that a portion of the natural gas produced from the San Juan Basin — Colorado Royalty Properties was sold on the spot market, and some of the natural gas produced from the San Juan Basin — Colorado Properties was sold pursuant to fixed price contracts. Under such fixed price contractual arrangements, the Trust may not benefit from increases in commodity prices to the extent a variable or market-based price arrangement would otherwise increase revenues to the Trust.

Market for Natural Gas

The amount of cash distributions by the Trust is dependent on, among other things, the sales prices realized for natural gas produced from the Royalty Properties and the quantities of gas sold. According to the U.S. Energy Information Administration of the Department of Energy, the average Henry Hub Natural Gas Spot Prices were $2.19 per MMBtu in 2024 and increased to $3.52 per MMBtu in 2025. Due to the seasonal nature of demand for natural gas and its effects on sales prices and production volumes, the amounts of cash distributions by the Trust may vary substantially on a seasonal basis. Generally, production volumes and prices are higher during the first and fourth quarters of each calendar year due primarily to peak demand in those periods. Because of the time lag between the date on which the Working Interest Owners receive payment for production from the Royalty Properties and the date on which distributions are made to unitholders, the seasonality that generally affects production volumes and prices is generally reflected in distributions to unitholders in later periods. Henry Hub Natural Gas Spot Prices are quoted in MMBtu, a commonly used energy measurement that has a conversion formula defined and published by the SEC for the purpose of estimating price per Mcf in the Reserve Report. Depending on the contractual arrangements and pricing applicable to production by the Working Interest Owners, the Trust may not benefit from increases in commodity prices as reported on the spot markets.

Competition

The production and sale of gas from the Royalty Properties are highly competitive, and the Working Interest Owners’ competitors in these areas include the major oil and gas companies, independent oil and gas companies, and individual producers and operators. There are numerous producers in the Hugoton field and the San Juan Basin. The Working Interest Owners have indicated that they believe that their competitive position in their respective areas is affected by price, contract terms and quality of service. Market conditions in the San Juan Basin may be negatively affected by the fact that most of the gas produced from such areas is transported on a limited number of major pipelines.

REGULATION AND PRICES

General

The production and sale of natural gas from the Royalty Properties are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production operations and economics, including levels of demand and pricing, are, or in the past have been, affected by price controls, taxes, conservation, safety, environmental and other laws relating to the petroleum industry, by changes in such laws, and by constantly changing administrative regulations. For example, on January 26, 2024, President Biden announced a temporary pause on pending decisions on new exports of liquified natural gas to countries that the United States does not have free trade agreements with, pending Department of Energy review of the underlying analyses for authorization. On January 20, 2025, President Trump reversed the pause on liquified natural gas and directed the Office of Fossil Energy and Carbon Management to resume consideration of pending applications to export liquified natural gas to countries without free trade agreements with the United States.

In March 2025, the EPA announced several regulatory actions seeking to alleviate the regulatory burden on the oil and gas industry. While the EPA reconsiders several rules impacting the exploration and production of oil and gas, it is likely that the current versions of the regulations will remain in effect during the process. Additionally, states remain active in environmental regulation and implementing climate related initiatives.

FERC Regulation

In general, the Federal Energy Regulatory Commission (the “FERC”) regulates the sale of natural gas in interstate commerce for resale and the transportation of natural gas in interstate commerce by pipelines, but does not regulate natural gas gathering facilities. Over thirty years ago, the FERC adopted regulations resulting in a restructuring of the natural gas industry. The principal elements of this restructuring were the requirement that interstate pipelines separate, or “unbundle,” into individual components the various services offered on their systems, with all transportation services to be provided on a nondiscriminatory basis, and the prohibition against an interstate pipeline providing gas sales services except through separately-organized affiliates. In various rulemaking proceedings following its initial unbundling requirement, the FERC has refined its regulatory program applicable to interstate pipelines in various respects, and it has announced that it will continue to monitor these and other regulations to determine whether further changes are needed. In addition to rulemaking proceedings, the FERC establishes new policies and regulations through policy statements and adjudications of individual pipeline matters. Further, additional changes to regulations may occur based on actions taken by Congress and/or the courts. As to these various developments, the Working Interest Owners have advised the Trust that the ongoing and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 and culminated in adoption of the Natural Gas Wellhead Decontrol Act that removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

Sales of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls at any time in the future. Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines in interstate commerce is subject to rate and access regulation by the FERC under the Interstate Commerce Act. In general, interstate oil pipeline rates must be just and reasonable and may be derived in a number of ways including, but not limited to, the FERC’s indexing methodology.

As to these various types of regulation, the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.

State and Other Regulation

Each of the jurisdictions encompassing the Royalty Properties has statutory provisions regulating the production and sale of crude oil and natural gas. The regulations often require permits for the drilling of wells and may specify rules related to the spacing of wells, the prevention of waste of oil and gas resources, the rate of production, the prevention and clean-up of pollution, and other matters.

State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint-based rate regulation.

Natural gas pipeline facilities used for the transportation of natural gas in interstate commerce are subject to federal minimum safety requirements. These requirements, however, are not applicable to, among other things, onshore gathering of gas (i) through a pipeline that operates at less than 0 psig; (ii) through a pipeline that is not a regulated onshore gathering line (as determined in 49 C.F.R. § 192.8); and (iii) within the inlets of the Gulf of America, except for the requirements in 49 C.F.R. § 192.612. The Royalty Properties are located in the Hugoton field of Kansas and the San Juan Basin of New Mexico and Colorado. Each of Colorado, Kansas and New Mexico has adopted the federal minimum safety requirements for intrastate pipelines within their borders. It is possible that future changes in applicable pipeline safety law may increase the stringency of the standards or expand the applicability of the standards to facilities not currently covered.

Environmental Matters

The Working Interest Owners’ operations are subject to numerous federal, state and local laws and regulations controlling the discharge and release of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations, including their state counterparts, can impose liability upon the owner, operator or lessee under a lease for the cost of cleanup of discharged and released materials or damages to natural resources resulting from oil and gas operations. These laws and regulations may, among other things:

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restrict the types, quantities and concentration of various substances that can be discharged and released into the environment in connection with oil and natural gas drilling and production activities;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

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require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

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Violations of environmental laws, regulations, or permits can result in civil and criminal penalties as well as potential injunctions curtailing operations in affected areas. The Working Interest Owners have advised the Trust that they are not at this time involved in any administrative or judicial proceedings relating to the Royalty Properties arising under federal, state or local environmental protection laws and regulations which would have a material adverse effect on the Working Interest Owners’ financial position or results of operations. The Working Interest Owners have also advised the Trust that they maintain insurance for costs of cleanup obligations, but that they are not fully insured against all such risks.

The following is a summary of certain material laws, rules and regulations to which the operations of the Royalty Properties may be subject.

Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, referred to as “CERCLA” or the Superfund law, and comparable state laws impose liability, potentially without regard to fault or legality of the activity at the time, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

The Royalty Properties have been used for oil and natural gas exploration and production for many years. Although the Working Interest Owners believe that they have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, the Royalty Properties may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under the Working Interest Owners’ control. These properties and the substances disposed or released on them may be subject to CERCLA, federal hazardous waste laws, and analogous state laws. Under such laws, the Working Interest Owners could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination regardless of whether or not such Working Interest Owner directly or indirectly caused the unpermitted discharge or release.

In addition, in the course of the Working Interest Owners’ operations, equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials (“NORM”). NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements. Because some properties presently or previously comprising the Royalty Properties may have been used for oil and natural gas production operations for many years, it is possible that the Working Interest Owners may incur costs or liabilities associated with elevated levels of NORM.

In February 2024, the Environmental Protection Agency (“EPA”) announced its plans to introduce proposed rules that target per- and polyfluoroalkyl substances (“PFAS”). PFAS are long-lasting chemicals used in a wide variety of consumer, commercial, and industrial products. Some states have already implemented regulations restricting levels of PFAS detected in soil, groundwater, and surface water. As the usage of PFAS, historically, has been widespread, it is possible that PFAS could have been released at the properties and could be subject to future promulgated health and safety standards.

Waste Handling. The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as “RCRA,” and comparable state statutes, regulate the management and disposal of solid and hazardous waste. Some wastes associated with the exploration and production of oil and natural gas are exempted from the most stringent regulation in certain circumstances, such as drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas. However, these wastes and other wastes may be otherwise regulated by the EPA or state agencies. Moreover, in the ordinary course of oil and gas operations, industrial wastes such as paint wastes and waste solvents may be regulated as hazardous waste under RCRA or considered hazardous substances under CERCLA. It is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.

Water Discharges. The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into regulated waters. The Oil Pollution Act of 1990 (the “OPA”), as amended, which amends the Clean Water Act, imposes strict liability on owners and operators of facilities that are the site of a release of oil into regulated waters. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. Spill prevention, control and countermeasure requirements under federal or state law may require appropriate operating protocols, including containment berms and similar structures, to help prevent or respond to a petroleum hydrocarbon spill, rupture or leak. In addition, the Clean

Water Act and analogous state laws may require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities or during construction activities.

Hydraulic Fracturing. It is customary to recover oil and natural gas from deep shale, tight sand and coal bed formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Conventional hydraulic fracturing techniques are used to increase production in vertical wells. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal Safe Drinking Water Act to exclude certain hydraulic fracturing activities from the definition of “underground injection.” At present, hydraulic fracturing is regulated at the state and local level. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal, state and local level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Repeal of the exemption would allow the EPA to promulgate new regulations. Many states have adopted rules that required operators to disclose chemicals and water volumes associated with hydraulic fracturing. In addition, hydraulic fracturing requires large amounts of water. This water, along with any produced water, is often sent to injection wells for disposal. This activity has been associated with earthquakes and some states, particularly Oklahoma, have limited injection well activity. If states in which the Working Interest Owners operate adopt limitations, it could have a negative impact on production.

Air Emissions. The federal Clean Air Act, and comparable state laws, restrict the emission of air pollutants from many sources, including drilling operations and related equipment, and as a result affect oil and natural gas operations. The EPA has also developed, and continues to give attention to, stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and gas operations. Air emissions permits may be required for some oil and gas production operations.

Climate Change. In January 2025, President Trump signed Executive Order, Unleashing American Energy, reversing several Biden-era climate policies and initiatives. While the EPA finalized a rule to reduce air pollutants from new and existing sources in the oil and gas industry with a particular focus on methane (the “Methane Rule”) in March 2024 seeking to reduce methane from oil and natural gas operations, the EPA announced that it will be reconsidering the rule in March 2025. On reconsideration, the EPA is likely to significantly pare the rule and its requirements back. In March 2024, the SEC adopted rules that will require public issuers to disclose specific climate-related information in their filings with the SEC. In February 2025, the SEC announced that it would no longer be defending challenges to its rules pertaining to the disclosure of climate specific information. While climate policies may be further rolled back at the federal level, some states have taken or proposed legal measures to reduce emissions of greenhouse gases. For example, a number of states, including states in which the Royalty Properties are located, have indicated an intent to reduce greenhouse gases through state action or regional partnerships. Similarly, Vermont and New York have enacted climate superfund laws that create strict liability compensatory damages on oil and gas producers that are deemed responsible for greenhouse gas emissions above a certain threshold for a period of time. Several other states have announced their intent to enact similar legislation which effectively seek to regulate global greenhouse gas emissions.

Safety. The Working Interest Owners are also subject to the requirements of the federal Occupational Safety and Health Act, known as “OSHA,” and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced by oil and gas operations and that this information be provided to employees, state and local government authorities and the public.