MESA ROYALTY TRUST/TX - Quarter Report: 2015 September (Form 10-Q)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

Commission File Number: 1-7884

MESA ROYALTY TRUST
(Exact name of registrant as specified in its charter)

1-713-483-6020
(Registrant's Telephone Number, Including Area Code)

The Bank of New York Mellon Trust Company, N.A.,
Trustee
919 Congress Avenue
Austin, Texas 78701
(Former name, former address and former fiscal year, if changed since last report)

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

         As of November 13, 2015—1,863,590 Units of Beneficial Interest were outstanding in Mesa Royalty Trust.

PART I—FINANCIAL INFORMATION

Item 1.    Financial Statements.

MESA ROYALTY TRUST

STATEMENTS OF DISTRIBUTABLE INCOME

(Unaudited)

(The accompanying notes are an integral part of these financial statements.)

2

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

(The accompanying notes are an integral part of these financial statements.)

3

MESA ROYALTY TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS

(Unaudited)

(The accompanying notes are an integral part of these financial statements.)

4

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1—Trust Organization and Provisions

        The Mesa Royalty Trust (the "Trust") was created on November 1, 1979. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership ("MLP"), which was the predecessor to MESA Inc., conveyed to the Trust an overriding royalty interest (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 certain producing oil and gas properties located in the Hugoton field of Kansas, the San Juan Basin field of New Mexico and Colorado and the Yellow Creek field of Wyoming (the "Royalty Properties"). The Royalty is evidenced by counterparts of an Overriding Royalty Conveyance dated as of November 1, 1979 (the "Conveyance"). On April 30, 1991, MLP sold its interests in the Royalty Properties located in the San Juan Basin field to ConocoPhillips. ConocoPhillips sold the portion of its interests in the San Juan Basin Royalty Properties located in Colorado 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 Colorado San Juan Basin Royalty Properties to BP Amoco Company ("BP"), a subsidiary of BP p.l.c. Until August 7, 1997, MESA Inc. operated the Hugoton Royalty Properties through Mesa Operating Co., a wholly owned subsidiary of MESA Inc. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("Pioneer"), formerly a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. (successor to Mesa Operating Co.), a wholly owned subsidiary of Pioneer ("PNR") (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, the Hugoton Royalty Properties were operated by PNR until December 31, 2014, at which point Linn Energy Holdings, LLC ("Linn") took over as operator. For the Trust's properties, there is a difference between production months for the operators and accounting months for the Trust. For the quarter ended September 30, 2015, the Hugoton Royalty Properties accounting months correspond with the April 2015 through June 2015 production months, during which time Linn served as operator. Substantially all of the San Juan Basin Royalty Properties located in New Mexico are operated by ConocoPhillips. Effective January 1, 2005, ConocoPhillips assigned its interest in an immaterial number of San Juan Basin Royalty Properties located in New Mexico to XTO Energy Inc. The San Juan Basin Royalty Properties located in Colorado are operated by BP. As used in this report, Linn refers to the current operator of the Hugoton Royalty Properties, ConocoPhillips refers to the operator of the San Juan Basin Royalty Properties, other than the portion of such properties located in Colorado, and BP refers to the operator of the Colorado San Juan Basin Royalty Properties unless otherwise indicated. On July 18, 2014, PNR entered into a purchase and sale agreement (the "Purchase Agreement") to sell all of its assets in the Hugoton field in Kansas to Linn. The transaction closed on September 11, 2014. The assets sold to Linn included, among other things, all of Pioneer's producing oil and gas wells, all of its interest in the Satanta gas processing plant and all other associated infrastructure. In connection with the Purchase Agreement, PNR and Linn also entered into a Transition Services Agreement, dated July 18, 2014, whereby PNR agreed to continue providing operating, certain administrative services, accounting and other services related to the assets in

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MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

exchange for a service fee. As a result, PNR continued to act as operator with respect to the Hugoton Royalty Properties through December 31, 2014. Upon expiration of the Transition Services Agreement, Linn took over as operator of the Hugoton Royalty Properties.

        Effective October 2, 2006, The Bank of New York Mellon Trust Company, N.A. (the "Trustee") succeeded JPMorgan Chase Bank, N.A. as Trustee of the Trust. JPMorgan Chase Bank, N.A. is the successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association. The terms of the Mesa Royalty Trust Indenture (the "Trust Indenture") 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 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;

        (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)    Linn, ConocoPhillips and BP (collectively the "Working Interest Owners") will reimburse the Trust for 59.34%, 27.45% and 1.77%, respectively, for general and administrative expenses of the Trust.

        During 2011, the Trustee withheld $1.0 million for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. At any given time, the amount currently reserved for such future unknown contingent liabilities and expenses is included in cash and short-term investments.

        As of September 30, 2015, there were $8,416 of unreimbursed expenses, including $1,733 from the quarter ended March 31, 2015 and $2,877 from the quarter ended June 30, 2015. The Trust anticipated receipt of these expense reimbursements by month-end when it published its March, June and September distribution press releases on March 20, 2015, June 17, 2015 and September 16, 2015, respectively, and included these amounts in distributions payable and distributable income per unit as of March 31, 2015, June 30, 2015 and September 30, 2015. 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. For the three months ended September 30, 2015, the Trustee decreased the reserve for future unknown contingent

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MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

liabilities and expenses by the amount of expected expense reimbursement cash receipts of $3,806. Additionally, the Trustee increased the reserve for future unknown contingent liabilities and expenses by the amounts received during the third quarter of 2015 related to expense reimbursement cash receipts for previous periods totaling $49,826 and by $17,990 of royalty income received from Linn Energy in September 2015 after the distribution to Unitholders had been announced for the month of September 2015. Such royalty income was included in the October 2015 distribution to Unitholders. As of September 30, 2015, the reserve for unknown contingent liabilities and expenses was $1,009,574, which was included in cash and short-term investments. The Trust has subsequently received $8,416 of the expected expense reimbursement cash receipts as of November 13, 2015, which has increased the reserve for unknown contingent liabilities and expenses. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses.

        The Trustee was due $118,750 for its services for the quarter ended September 30, 2015. The Trust paid $108,288 of this amount to the Trustee, and $10,462 was allocated to offset against interest due to the Trust under the Trust Indenture. The Trust Indenture requires that cash being held by the Trustee earn interest at 1.5% below the prime rate, which would have yielded the Trust a 1.75% return as of September 30, 2015. However, due to the current interest rate environment, the Trustee was unable to obtain an account in which such an interest rate was available. In the event such an interest rate is unavailable in the future, the Trustee intends to allocate certain of its fees due to the Trust to meet the minimum interest rate payable under the Trust Indenture. The Trustee will continue to allocate a portion of the fees earned for its services to the Trust until the remaining $63,628 of interest due to the Trust is fully offset, and it may do so in future periods in which unpaid interest is due to the Trust. The working interest owners partially reimburse the Trust each quarter for amounts paid in connection with the Trustee's services. For the quarter ended September 30, 2015, such reimbursements totaled $95,900. For year to date September 30, 2015 such fees were $324,965. Reimbursements received for year to date September 30, 2015 were $287,787. For the quarter ended September 30, 2014 and year to date September 30, 2014, trustee fees were $108,288 and $300,514, respectively. Reimbursements received for the quarter ended September 30, 2014 and year to date September 30, 2014 were $95,900 and $266,135, respectively.

        The Trustee engaged an independent consulting firm to audit revenues, expenses and established reserves of certain working interest owners. As a result of the audit, the Trustee and PNR entered into a Settlement Agreement, dated effective as of February 21, 2014, pursuant to which PNR agreed to pay the Trust for certain audit exceptions noted by the Trustee for calendar years 2006 through 2013. As such, the Trust income distribution for the month of April 2014 included $881,595 from PNR. The Trustee agreed to release PNR from any claims related to any of the matters raised in the audit exceptions for any year prior to 2013 and all such exceptions are deemed closed. The Trust income distribution for the month of September 2014 also included $52,868 from PNR and $369,585 from BP. PNR advised the Trustee that the $52,868 amount represents the Trust's share of an audit settlement completed regarding the Satanta plant. BP advised the Trustee that the $369,585 amount includes the

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MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

Trust's share of an audit adjustment related to prior periods. Amounts received from PNR and BP for the twelve months ended December 31, 2014 were $934,463 and $369,585, respectively. No amounts have been received related to audit adjustments for the year to date September 30, 2015. While these audits have highlighted issues that remain open, the Trustee has not made a determination at this time whether any additional audit exceptions will result in any material gains or expenses net to the Trust.

Note 2—Basis of Presentation

        The accompanying unaudited financial information has been prepared by the Trustee in accordance with the instructions to Form 10-Q. The preparation of the financial statements requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of income and expenses during the reporting period. Actual results could differ from those estimates. The Trustee believes such information includes all the disclosures necessary to make the information presented not misleading. The information furnished reflects all adjustments which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim periods presented. The financial information should be read in conjunction with the financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2014. The Trust considers all highly liquid investments with a maturity of three months or less to be cash equivalents. Subsequent events were evaluated through the issuance date of the financial statements.

        In accordance with the Conveyance, the Working Interest Owners are obligated to calculate and pay the Trust each month an amount equal to 90% of the Net Proceeds (as defined in the Conveyance) attributable to the month. 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.

        The financial statements of the Trust are prepared on the following basis:

        (a)   Royalty income recorded for a month is the amount computed and paid by the Working Interest Owners to the Trustee for such month rather than either the value of a portion of the oil and gas produced by the Working Interest Owners for such month or the amount subsequently determined to be the Trust's proportionate share of the Net Proceeds for such month;

        (b)   Interest income, interest receivable and distributions payable to unitholders include interest to be earned on short-term investments from the financial statement date through the next date of distribution;

        (c)   Trust general and administrative expenses, net of reimbursements, are recorded in the month they are included in the calculation of the monthly distribution amount;

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MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Basis of Presentation (Continued)

        (d)   Amortization of the Royalty is computed on a unit-of-production basis and is charged directly to trust corpus since such amount does not affect distributable income; and

        (e)   Distributions payable are determined on a monthly basis and are payable to unitholders of record as of the last business day of each month or such later date as the Trustee determines is required to comply with applicable law or stock exchange requirements. However, cash distributions are made quarterly in January, April, July and October, and include interest earned from the monthly record dates to the date of distribution.

        This basis for reporting distributable income is considered to be the most meaningful because distributions to the unitholders for a month are based on net cash receipts for such month. However, these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America because, under such principles, royalty income for a month would be based on net proceeds from production for such month without regard to when calculated or received, general and administrative expenses would be recorded in the month they accrue, and interest income for a month would be calculated only through the end of such month.

Note 3—Legal Proceedings

        There are no pending legal proceedings to which the Trust is a named party. The Trustee has been advised by Linn, ConocoPhillips and BP that it is subject to litigation in the ordinary course of business for certain matters that include the Royalty Properties. While each of the working interest owners has advised the Trustee that it does not currently believe any of the pending litigation will have a material adverse effect net to the Trust, in the event such matters were adjudicated or settled in a material amount and charges were made against Royalty income, such charges could have a material impact on future Royalty income.

Note 4—Income Tax Matters

        In a technical advice memorandum dated February 26, 1982, 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 the unitholder's pro rata share of the income and expense of the Trust as if the 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.

        For taxable years beginning after December 31, 2012, individuals, estates, and trusts with income above certain thresholds are subject under Section 1411 of the Internal Revenue Code to an additional 3.8% tax—also known as the "Medicare contribution tax"—on their net investment income. Grantor trusts such as Mesa Royalty Trust are not subject to the 3.8% tax; however, the unitholders may be subject to the tax. For these purposes, investment income would generally include certain income

9

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4—Income Tax Matters (Continued)

derived from investments, such as the royalty income derived from the units and gain realized by a unitholder from a sale of units.

        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. The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Floor 17, Houston, Texas 77002, telephone number 713-483-6020, 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.

        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 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.

Note 5—Excess Production Costs

        Excess production costs result when costs, charges, and expenses attributable to a Working Interest Property exceed the revenue received from the sale of oil, gas, and other hydrocarbons produced from such property. The excess production costs must be recovered by the working interest owners before any distribution of Royalty income from the properties will be made to the Trust. As of September 30, 2015 and December 31, 2014, there were $192,109 and $478, respectively, of excess production costs. Excess production costs in the amounts of $777 and $478 as of September 30, 2015 and December 31, 2014, respectively, related to the San Juan Basin—New Mexico properties operated by XTO Energy Inc. XTO Energy Inc. made distributions to the Trust during the first and second quarters of 2015 without recovering the excess production costs. The remainder of the excess production costs in the amount of $191,332 as of September 30, 2015 related to the San Juan Basin—Colorado properties operated by BP and Red Willow. Excess production costs related to the San Juan Basin—Colorado properties operated by BP were approximately $187,089 as of September 30, 2015. As of March 31, 2015 and June 30, 2015 there were excess production costs of $33,359 and $48,816, respectively, related to the San Juan Basin—Colorado properties operated by BP. The trust recovered prior period excess production costs of $31,328 during the quarter ended June 30, 2015 and $3,891 during the quarter ended September 30, 2015. Excess production costs related to the San Juan Basin—Colorado properties operated by Red Willow were approximately $4,243 as of September 30, 2015.

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MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 6—Distributable Income Per Unit

        During 2011, the Trustee withheld $1.0 million for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. For the three months ended September 30, 2015, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $3,806 and increased the reserve for future unknown contingent liabilities and expenses by the amounts received during the third quarter of 2015 related to expense reimbursement cash receipts for previous periods totaling $49,826. Additionally, the Trustee increased the reserve for future unknown contingent liabilities and expenses by $17,990 of royalty income received from Linn Energy in September 2015 after the distribution to Unitholders had been announced for the month of September 2015. Such royalty income was included in the October 2015 distribution to Unitholders. The effect on distributable income per unit is as follows:

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

        The following review of the Trust's financial condition and results of operations should be read in conjunction with the financial statements and notes thereto. The discussion of net production attributable to the Hugoton and San Juan properties represents production volumes that are to a large extent hypothetical, as the Trust does not own and is not entitled to any specific production volumes. See Note 9 to the financial statements in the Trust's Annual Report on Form 10-K for the year ended December 31, 2014. Any discussion of "actual" production volumes represents the hydrocarbons that were produced from the properties in which the Trust has an overriding royalty interest.

        The Trust is a passive entity whose purposes are limited to: (1) converting the Royalties to cash, either by retaining them and collecting the proceeds of production (until production has ceased or the Royalties are otherwise terminated) or by selling or otherwise disposing of the Royalties; 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.

Note Regarding Forward-Looking Statements

        This Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-Q, including without limitation the statements under "Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements. Although the Working Interest Owners have advised the Trust that they believe that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove to be correct. Important factors that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-Q and in the Trust's Annual Report on Form 10-K for the year ended December 31, 2014, including under "Item 1A. Risk Factors". All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements.

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SUMMARY OF ROYALTY INCOME, PRODUCTION AND AVERAGE PRICES
(Unaudited)

        Royalty income is computed after deducting the Trust's proportionate share of capital costs, operating costs and interest on any cost carryforward from the Trust's proportionate share of "Gross Proceeds," as defined in the Conveyance. The following summary illustrates the net effect of the components of the actual Royalty computation for the periods indicated.

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Three Months Ended September 30, 2015 and 2014

Financial Review

        The Trust's Royalty income was $401,139 in the third quarter of 2015, a decrease of approximately 78% as compared to $1,810,554 in the third quarter of 2014, primarily as a result of lower natural gas and natural gas liquids prices, reduced production of natural gas and natural gas liquids and increased capital expenditures and operating costs in the third quarter of 2015 as compared to the third quarter of 2014. In addition, the Trust income distribution for the month of September 2014 included $52,868 from PNR and $369,585 from BP. PNR advised the Trustee that the $52,868 amount represents the Trust's share of an audit settlement completed regarding the Satanta plant. BP advised the Trustee that the $369,585 amount includes the Trust's share of an audit adjustment related to prior periods.

        General and Administrative income for the quarter ended September 30, 2015 was $10,823 which was the result of net reimbursements of $49,826 from the second quarter of 2015 exceeding Trust expenses of $39,003 for the third quarter of 2015.

        The distributable income available for distribution of the Trust for each period includes the Royalty income received from the working interest owners during such period, plus interest income earned to the date of distribution (if any) and increases or withdrawals from the reserve for contingent liabilities and expenses (if any). Trust administration expenses are deducted in the computation of distributable income available for distribution. Distributable income available for distribution for the quarter ended September 30, 2015 was $347,952, representing $0.1867 per unit, compared to

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$1,773,998, representing $0.9519 per unit, for the quarter ended September 30, 2014. Based on 1,863,590 units outstanding for the quarters ended September 30, 2015 and 2014, respectively, the per unit distributions were as follows:

        As of September 30, 2015, there were $8,416 of unreimbursed expenses, including $1,733 from the quarter ended March 31, 2015 and $2,877 from the quarter ended June 30, 2015. The Trust anticipated receipt of these expense reimbursements by month-end when it published its March, June and September distribution press releases on March 20, 2015, June 17, 2015 and September 16, 2015, respectively, and included these amounts in distributions payable and distributable income per unit as of March 31, 2015, June 30, 2015 and September 30, 2015. 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. During 2011, the Trustee withheld $1.0 million for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. At any given time, the amount currently reserved for such future unknown contingent liabilities and expenses is included in cash and short-term investments. For the three months ended September 30, 2015, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $3,806. Additionally, the Trustee increased the reserve for future unknown contingent liabilities and expenses by the amounts received during the third quarter of 2015 related to expense reimbursement cash receipts for previous periods totaling $49,826 and by $17,990 of royalty income received from Linn Energy in September 2015 after the distribution to Unitholders had been announced for the month of September 2015. Such royalty income was included in the October 2015 distribution to Unitholders. As of September 30, 2015, the reserve for unknown contingent liabilities and expenses was $1,009,574, which was included in cash and short term investments. The Trust has subsequently received $8,416 of the expected expense reimbursement cash receipts as of November 13, 2015, which has increased the reserve for unknown contingent liabilities and expenses. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses.

Operational Review

Hugoton Field

        Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 38% of the Royalty income of the Trust during the third quarter of 2015.

        Linn has advised the Trust that since June 1, 1995 natural gas produced from the Hugoton field has generally been sold under short-term and multi-month contracts at market clearing prices to multiple purchasers. During 2014 the primary purchaser was Oneok Gas Marketing, Inc. Linn has advised the Trust that it expects to continue to market gas production from the Hugoton field under short-term and multi-month contracts. As discussed below, overall market prices received for natural

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gas from the Hugoton Royalty Properties were lower in the third quarter of 2015 compared to the third quarter of 2014.

        In June 1994, PNR entered into a Gas Transportation Agreement ("Gas Transportation Agreement") with Western Resources, Inc. ("WRI") for a primary term of five years, commencing June 1, 1995. Thereafter, this contract has renewed on a year to year basis. WRI subsequently assigned its rights and obligations under the Gas Transportation Agreement to Oneok Field Services ("Oneok"), and PNR subsequently assigned its rights and obligations under the Gas Transportation Agreement to Linn. The current term will remain in effect through May 31, 2016, at which point Oneok has provided notice to terminate. Pursuant to the terms of the Gas Transportation Agreement, WRI initially agreed to compress and transport up to 160 MMcf per day of gas and redeliver such gas to PNR at the inlet of PNR's Satanta Plant. PNR agreed to pay WRI a fee of $0.06 per Mcf escalating 4% annually as of June 1, 1996.

        Royalty income attributable to the Hugoton Royalty decreased to $152,433 in the third quarter of 2015 from $599,284 in the third quarter of 2014 primarily due to decreases in natural gas and natural gas liquids prices and lower natural gas and natural gas liquids volumes, offset in part by reduced capital expenditures and lower operating costs from the Hugoton Royalty Properties. In addition, the Trust income distribution for the month of September 2014 included $52,868. PNR advised the Trust that such amount represents the Trust's share of an audit settlement completed regarding the Satanta plant.

        The average price received in the third quarter of 2015 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $3.08 per Mcf and $12.87 per barrel, respectively, as compared to $4.79 per Mcf and $34.15 per barrel, respectively, in the third quarter of 2014. Net production of natural gas attributable to the Hugoton Royalty decreased to 36,205 Mcf in the third quarter of 2015 from 72,886 Mcf in the third quarter of 2014. Net production of natural gas liquids attributable to the Hugoton Royalty decreased to 3,171 barrels in the third quarter of 2015 from 5,777 barrels in the third quarter of 2014. Actual production volumes from the Hugoton properties decreased to 96,115 Mcf of natural gas and 8,583 barrels of natural gas liquids in the third quarter of 2015 as compared to 113,184 Mcf of natural gas and 8,970 barrels of natural gas liquids for the same period in 2014.

        The Hugoton capital expenditures were $124 in the third quarter of 2015, as compared to $3,472 in the third quarter of 2014. Operating costs were $254,170 in the third quarter of 2015, a decrease of approximately 15% as compared to $297,941 in the third quarter of 2014. The decrease in operating costs was due primarily to cost saving initiatives.

San Juan Basin

        Royalty income from the San Juan Basin Royalty Properties is calculated and paid to the Trust on a state-by-state basis. Substantially all of the royalty income from the San Juan Basin Royalty Properties is attributable to the Royalty Properties located in the State of New Mexico.

        Royalty income from the San Juan Basin—New Mexico was $248,706 during the third quarter of 2015 as compared with Royalty income of $738,626 during the third quarter of 2014. This decrease in Royalty income was due primarily to a decrease in natural gas and natural gas liquids prices, decreased production of natural gas liquids and an increase in capital expenditures, offset in part by increased natural gas production and lower operating costs for the third quarter of 2015 compared to the third

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quarter of 2014. Net production attributable to the San Juan Basin Royalty Properties located in New Mexico was 108,819 Mcf of natural gas and 4,962 barrels of natural gas liquids in the third quarter of 2015, as compared to 126,053 Mcf of natural gas and 12,880 barrels of natural gas liquids in the third quarter of 2014. The average price received in the third quarter of 2015 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties located in the State of New Mexico was $1.54 per Mcf and $16.35 per barrel, respectively, compared to $3.72 per Mcf and $20.94 per barrel during the same period in 2014. Actual production volumes of natural gas attributable to the San Juan Basin Royalty Properties located in the State of New Mexico increased to 236,389 Mcf in the third quarter of 2015 from 187,907 Mcf of natural gas for the same period in 2014. Actual production volumes of natural gas liquids attributable to the San Juan Basin Royalty Properties located in the State of New Mexico decreased to 14,687 barrels in the third quarter of 2015 from 21,169 barrels for the same period in 2014. The overall decrease in production volumes is consistent with a normal decline in production for this field.

        Capital expenditures on these properties were $56,553 in the third quarter of 2015, an increase of approximately 45% as compared to $39,063 in the third quarter of 2014. The increase in capital expenditure was due to increased spending on facilities in the third quarter of 2015 compared with the third quarter of 2014. Operating costs were $236,055 in the third quarter of 2015, a decrease of approximately 27% as compared to $322,789 in the third quarter of 2014 due to a decrease in severance taxes due to the natural decline in volumes from the field as well as the decline in the price of natural gas and natural gas liquids.

        The Trust's interest in the San Juan Basin was conveyed from PNR's working interest in 31,328 net producing acres in northwestern New Mexico and southwestern Colorado. Substantially all of the natural gas produced from the San Juan Basin is currently being sold on the spot market.

        Royalty income from the San Juan Basin—Colorado Royalty Properties was $0 during the third quarter of 2015, compared to $482,644 during the third quarter of 2014. This decrease in Royalty income was due primarily to increased operating expenses in the third quarter of 2015 compared to the third quarter of 2014, a decrease in the price received for natural gas and lower natural gas production in the third quarter of 2015 compared to the third quarter of 2014. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 0 Mcf of natural gas during the third quarter of 2015 with 144,089 Mcf of natural gas attributable to the Trust during the third quarter of 2014. The average price received in the third quarter of 2015 for natural gas sold from the San Juan Basin Colorado Properties was $1.38 per Mcf, as compared to average price of $3.35 per Mcf for the third quarter of 2014. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 75,478 Mcf of natural gas in the third quarter of 2015 from 155,308 Mcf of natural gas for the same period in 2014.

        Operating costs on these properties were $244,937 in the third quarter of 2015 as compared to $36,929 in the third quarter of 2014 due primarily to repairs and recompletions in the third quarter of 2015 compared with the third quarter of 2014.

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Nine Months Ended September 30, 2015 and 2014

Financial Review

        The Trust's Royalty income was $1,647,067 for the nine months ended September 30, 2015, a decrease of approximately 70% as compared to $5,542,798 for the nine months ended September 30, 2014, primarily as a result of decreased natural gas and natural gas liquids prices and production volumes, offset in part by reduced capital expenditures and lower operating costs in the first nine months of 2015 as compared to the first nine months of 2014. In addition, the Trust income distribution for the month of April 2014 included $881,595. The Trustee engaged an independent consulting firm to audit revenues and expenses of certain working interest owners. As a result of the audit, the Trustee entered into a Settlement Agreement with one of the working interest owners, pursuant to which such working interest owner agreed to pay the Trust for certain audit exceptions noted by the Trustee for the calendar years 2006 through 2013. The Trust income distribution for the month of September 2014 also included $52,868 from PNR and $369,585 from BP. PNR advised the Trustee that the $52,868 amount represents the Trust's share of an audit settlement completed regarding the Satanta plant. BP advised the Trustee that the $369,585 amount includes the Trust's share of an audit adjustment related to prior periods. Amounts received from PNR and BP for the nine months ended September 30, 2014 were $934,463 and $369,585, respectively.

        The distributable income available for distribution of the Trust for each period includes the Royalty income received from the working interest owners during such period, plus interest income earned to the date of distribution (if any) and increases or withdrawals from the reserve for contingent liabilities and expenses (if any). Trust administration expenses are deducted in the computation of distributable income available for distribution. Distributable income available for distribution for the nine months ended September 30, 2015 was $1,507,250, representing $0.8088 per unit, compared to $1,773,998, representing $0.9519 per unit, for the quarter ended September 30, 2014.

        As of September 30, 2015, there were $8,416 of unreimbursed expenses, including $1,733 from the quarter ended March 31, 2015 and $2,877 from the quarter ended June 30, 2015. The Trust anticipated receipt of these expense reimbursements by month-end when it published its March, June and September distribution press releases on March 20, 2015, June 17, 2015 and September 16, 2015, respectively, and included these amounts in distributions payable and distributable income per unit as of March 31, 2015, June 30, 2015 and September 30, 2015. 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. During 2011, the

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Trustee withheld $1.0 million for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. At any given time, the amount currently reserved for such future unknown contingent liabilities and expenses is included in cash and short-term investments. For the nine months ended September 30, 2015, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $174,126. Additionally, the Trustee increased the reserve for future unknown contingent liabilities and expenses by the amounts received during the nine months ended September 30, 2015 related to expense reimbursement cash receipts for previous periods totaling $165,710 and by $17,990 of royalty income received from Linn Energy in September 2015 after the distribution to Unitholders had been announced for the month of September 2015. Such royalty income was included in the October 2015 distribution to Unitholders. As of September 30, 2015, the reserve for unknown contingent liabilities and expenses was $1,009,574, which was included in cash and short term investments. The Trust has subsequently received $8,416 of the expected expense reimbursement cash receipts as of November 13, 2015, which has increased the reserve for unknown contingent liabilities and expenses. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses.

Operational Review

Hugoton Field

        Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 44% of the Royalty income of the Trust during the nine months ended September 30, 2015.

        Royalty income attributable to the Hugoton Royalty Properties decreased to $729,390 for the nine months ended September 30, 2015 from $2,533,561 for the same period in 2014 primarily due to lower prices for natural gas and natural gas liquids, lower natural gas and natural gas liquids production volumes, offset in part by reduced operating costs and capital expenditures from the Hugoton Royalty Properties in the first nine months of 2015 compared to the first nine months of 2014. In addition, the Trust income distribution for the month of April 2014 included $881,595. The Trustee engaged an independent consulting firm to audit revenues and expenses of certain working interest owners. As a result of the audit, the Trustee entered into a Settlement Agreement with one of the working interest owners, pursuant to which such working interest owner agreed to pay the Trust for certain audit exceptions noted by the Trustee for the calendar years 2006 through 2013. The Trust income distribution for the month of September 2014 also included $52,868. PNR advised the Trustee that such amount represents the Trust's share of an audit settlement completed regarding the Satanta plant. The average price received in the first nine months of 2015 for natural gas and natural gas liquids sold from the Hugoton field was $3.54 per Mcf and $14.48 per barrel, respectively, compared to $4.60 per Mcf and $37.56 per barrel, respectively, during the same period in 2014. Net production attributable to the Hugoton Royalty Properties decreased to 156,549 Mcf of natural gas and 12,053 barrels of natural gas liquids for the nine months ended September 30, 2015 as compared to 217,071 Mcf of natural gas and 15,990 barrels of natural gas liquids for the nine months ended September 30, 2014. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 304,013 Mcf of natural gas and 24,791 barrels of natural gas liquids in the nine months ended September 30, 2015 as compared to 342,170 Mcf of natural gas and 25,309 barrels of natural gas liquids for the same period in 2014. The decrease in natural gas and natural gas liquids volumes was due primarily to natural decline as well as

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a reduced capital program due to the lower commodity price environment during the third quarter of 2015 compared with the third quarter of 2014.

        Capital expenditures on these properties were $10,388 during the nine months ended September 30, 2015, a decrease of approximately 54% as compared to $22,633 during the nine months ended September 30, 2014. Operating costs were $696,088 during the nine months ended September 30, 2015, a decrease of approximately 23% as compared to $901,649 during the nine months ended September 30, 2014 due to cost saving initiatives.

San Juan Basin

        Royalty income from the San Juan Basin—New Mexico was $900,128 for the first nine months of 2015 compared to $2,406,434 for the first nine months of 2014. The decrease in Royalty income was due primarily to lower natural gas and natural gas liquids prices and lower production volumes for both natural gas and natural gas liquids, offset in part by reduced capital expenditures and lower operating costs in the first nine months of 2015 from the San Juan Basin properties compared to the same period in 2014. The average price received in the nine months ended September 30, 2015 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $2.07 per Mcf and $14.39 per barrel, respectively, compared to $3.75 per Mcf and $24.52 per barrel, respectively, during the same period in 2014. Net production attributable to the San Juan Basin Royalty located in New Mexico was 300,704 Mcf of natural gas and 19,358 barrels of natural gas liquids for the nine months ended September 30, 2015 as compared to 382,828 Mcf of natural gas and 39,600 barrels of natural gas liquids for the nine months ended September 30, 2014. Actual production volumes attributable to the San Juan Basin Royalty Properties increased to 595,859 Mcf of natural gas and decreased to 44,368 barrels of natural gas liquids in the nine months ended September 30, 2015 as compared to 571,565 Mcf of natural gas and 65,663 barrels of natural gas liquids for the same period in 2014.

        San Juan Basin—New Mexico capital expenditures were $118,127 during the nine months ended September 30, 2015, a decrease of approximately 24% as compared to $155,829 during the nine months ended September 30, 2014. This decrease is due to decreased spending on facilities during the nine months ended September 30, 2015 when compared to the nine months ended September 30, 2014. Operating costs were $772,781 during the nine months ended September 30, 2015, a decrease of approximately 26% as compared to $1,039,877 during the nine months ended September 30, 2014. The decrease in operating costs was primarily affected by the decrease in severance taxes due to the natural decline in volumes from the field as well as the decline in the price of natural gas and natural gas liquids.

        Royalty income from the San Juan Basin—Colorado was $17,549 for the nine months ended September 30, 2015, compared to $612,803 during the same period in 2014. The Trust income distribution for the month of September 2014 included $369,585 from BP. BP advised the Trustee that $369,585 amount includes the Trust's share of an audit adjustment related to related to prior periods. The decrease in Royalty income was primarily the result of increased operating costs, lower prices for natural gas and reduced natural gas production in the nine months ended September 30, 2015 compared to the same period in 2014. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 9,099 Mcf of natural gas during the nine months ended September 30, 2015 with 188,610 Mcf of natural gas attributable to the Trust during the same period in 2014. The average price received for the nine months ended September 30, 2015 for natural gas sold

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from the San Juan Basin—Colorado properties was $1.93 per Mcf, compared to $3.25 per Mcf received during the same period in 2014. Actual production volumes attributable to the San Juan Basin—Colorado properties decreased to 204,700 Mcf of natural gas for the nine months ended September 30, 2015 as compared to 250,793 Mcf of natural gas for the same period in 2014.

        Operating costs on these properties were $563,410 for the nine months ended September 30, 2015 an increase of approximately 179% as compared to $201,863 in the same period in 2014 due primarily to the increase in repairs and recompletions in the nine months ended September 30, 2015 compared to the same period in 2014.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

        The Trust does not engage in any operations, and does not utilize market risk sensitive instruments, either for trading purposes or for other than trading purposes. The Trust's monthly distributions are highly dependent upon the prices realized from the sale of natural gas and natural gas liquids. Natural gas and natural gas liquids 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 and the working interest owners. Factors that contribute to price fluctuation include, among others:

•

political conditions worldwide, in particular political disruption, war or other armed conflict in or affecting oil producing regions;



•

worldwide economic conditions;



•

weather conditions, including hurricanes and tropical storms in the Gulf of Mexico;



•

the supply and price of foreign natural gas;



•

the level of consumer demand;



•

the price and availability of alternative fuels;



•

the proximity to, and capacity of, transportation facilities; and



•

the effect of worldwide energy conservation measures.

        Moreover, government regulations, such as regulation of natural gas transportation and regulation of greenhouse gas and other emissions associated with fossil fuel combustion and price controls, can affect product prices in the long term.

Item 4.    Controls and Procedures.

        Evaluation of Disclosure Controls and Procedures.    The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is accumulated and communicated by the working interest owners to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

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        As of the end of the period covered by this report, the trust officer acting on behalf of the Trustee responsible for the administration of the Trust conducted an evaluation of the Trustee's disclosure controls and procedures. The officer acting on behalf of the Trustee concluded that the Trust's disclosure controls and procedures were effective.

        Due to the contractual arrangements of (i) the Trust Indenture and (ii) the rights of the Trust under the Conveyance regarding information furnished by the working interest owners, the Trustee relies on information provided by the working interest owners, including (i) the status of litigation, (ii) historical operating data, plans for future operating and capital expenditures and reserve information, (iii) information relating to projected production, and (iv) conclusions regarding reserves by their internal reserve engineers or other experts in good faith. See Part I, Item 1A. "Risk Factors—"Trust unitholders and the Trustee have no control over the operation or development of the Royalty Properties and have little influence over operation or development" and "The Trustee relies upon the working interests owners for information regarding the Royalty Properties" in the Trust's Annual Report on Form 10-K for the year ended December 31, 2014 for a description of certain risks relating to these arrangements and reliance, including filings such as this filing outside the time periods specified notwithstanding effective disclosure controls and procedures of the Trustee regarding information under its control.

        The officer acting on behalf of the Trustee has not conducted a separate evaluation of the disclosure controls and procedures with respect to information furnished by the working interest owners. The Trustee notes that it is conducting an ongoing review of certain information and calculations by the working interest owners, along with an outside joint venture auditor. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" under Item 7 on Form 10-K for the year ended December 31, 2014 for information concerning controls and procedures with respect to the Royalty.

        Changes in Internal Control over Financial Reporting.    In connection with the evaluation by the Trustee of changes in internal control over financial reporting of the Trust that occurred during the Trust's last fiscal quarter, no change in the Trust's internal control over financial reporting was identified that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning the internal control over financial reporting of the working interest owners.

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PART II—OTHER INFORMATION

Item 1.    Legal Proceedings.

        There are no pending legal proceedings to which the Trust is a named party. The Trustee has been advised by Linn, ConocoPhillips and BP that it is subject to litigation in the ordinary course of business for certain matters that include the Royalty Properties. While each of the working interest owners has advised the Trustee that it does not currently believe any of the pending litigation will have a material adverse effect net to the Trust, in the event such matters were adjudicated or settled in a material amount and charges were made against Royalty income, such charges could have a material impact on future Royalty income.

Item 1A.    Risk Factors.

        There have not been any material changes from risk factors previously disclosed in Item 1A to Part I of the Trust's Annual Report on Form 10-K for the year ended December 31, 2014.

Item 6.    Exhibits.

        (Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. The Bank of New York Mellon Trust Company, N.A. is the successor trustee to JPMorgan Chase Bank, N.A. JPMorgan Chase Bank, N.A. was formerly known as The Chase Manhattan Bank and was successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association).

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SIGNATURES

        Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: November 13, 2015

        The Registrant, Mesa Royalty Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided.

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QuickLinks

Item 1. Financial Statements.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Item 4. Controls and Procedures.

Item 1. Legal Proceedings.
Item 1A. Risk Factors.
Item 6. Exhibits.