MESA ROYALTY TRUST/TX - Quarter Report: 2017 June (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)

         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, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

         If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

         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 August 14, 2017—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)

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

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

1

MESA ROYALTY TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS

(Unaudited)

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

2

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 (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. 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.

        Effective October 2, 2006, The Bank of New York Mellon Trust Company, N.A. (the "Trustee") succeeded JP Morgan 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 (as amended, 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;

3

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

        (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.

        On May 11, 2016, Linn Energy, LLC ("Old Linn"), LinnCo, LLC ("LinnCo"), an affiliate of Old Linn, and certain of Old Linn's direct and indirect subsidiaries (collectively with Old Linn and LinnCo, the "Debtors"), filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the "Court"). The Debtors' Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040.

        On January 27, 2017, the Court entered the Order Confirming (I) Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC and (II) Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC, which approved and confirmed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the "Plan"). The Plan became effective on February 28, 2017 (the "Effective Date").

        Pursuant to the Plan, on the Effective Date, all assets of Old Linn (other than equity interests in Linn Acquisition Company, LLC and Berry Petroleum Company, LLC) were conveyed to Linn Energy, Inc. (or a subsidiary thereof), and LinnCo, LLC and Linn Energy, LLC were wound down and liquidated. Subsequent to the effectiveness of the Plan, Linn Energy, Inc. is now the reorganized successor to Old Linn. Under the Plan Supplement, as amended, filed with the Court, the Debtors assumed all executory contracts and unexpired leases with the Trust and Mesa Operating Limited Partnership as the counterparty. Furthermore, pursuant to the Plan, the royalty interests in the Hugoton Royalty Properties owned by the Trust shall be preserved and remain in full force and effect in accordance with the terms of the granting instruments or other governing documents.

4

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

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, 2016. 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;

        (d)   Amortization of the Royalty is computed on a unit-of-production basis and is charged directly to trust corpus because 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

5

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Basis of Presentation (Continued)

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 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

6

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4—Income Tax Matters (Continued)

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 16, 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 June 30, 2017 and December 31, 2016, there were $18,440 and $19,983, respectively, of excess production costs. Excess production costs in the amount of $3,473 and $3,591 as of June 30, 2017 and December 31, 2016, respectively, related to the San Juan Basin—New Mexico properties operated by XTO Energy Inc. The remainder of the excess production costs in the amount of $14,967 as of June 30, 2017 and $16,392 as of December 31, 2016, 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 $0 and $3,860 as of June 30, 2017 and December 31, 2016, respectively. Excess production costs related to the San Juan Basin—Colorado properties operated by Red Willow were approximately $14,967 and $12,532 as of June 30, 2017 and December 31, 2016, respectively. Red Willow made a $147 distribution to the Trust in error during the first quarter of 2017 without recovering the $13,832 excess production costs as of March 31, 2017. Such funds were returned to Red Willow in April 2017.

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. 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 June 30, 2017, the Trustee increased the reserve for future unknown contingent liabilities and expenses by $47,840 of royalty income received from BP in June 2017 after the distribution to unitholders had been announced for the month of June 2017. Such royalty income

7

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 6—Distributable Income Per Unit (Continued)

was included in the July 2017 distribution to unitholders. For the three months ended June 30, 2017, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by $82,244 of royalty income received from BP in March 2017 after the distribution to unitholders had been announced for the month of March 2017. Such royalty income was included in the April 2017 distribution to unitholders. For the six months ended June 30, 2017, the Trustee increased the reserve for future unknown contingent liabilities and expenses by (1) $82,244 of royalty income received from BP in March 2017 after the distribution to unitholders had been announced for the month of March 2017 which royalty income was included in the April 2017 distribution to unitholders, and (2) $47,840 of royalty income received from BP in June 2017 after the distribution to unitholders had been announced for the month of June 2017 which royalty income was included in the July 2017 distribution to unitholders. For the six months ended June 30, 2017, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by $82,244 of royalty income received from BP, such that as of June 30, 2017, the reserve for unknown contingent liabilities and expenses was $1,047,840 and is included in cash and short-term investments. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any reimbursement expenses. The effect on distributable income per unit is as follows:

8

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, 2016. 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, 2016, 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.

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

9

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.

10

11

Three Months Ended June 30, 2017 and 2016

Financial Review

        The Trust's Royalty income was $717,229 in the second quarter of 2017, an increase of approximately 292% as compared to $182,988 in the second quarter of 2016, primarily as a result of higher natural gas, natural gas liquids and oil and condensate prices, increased net production of natural gas, natural gas liquids and oil and condensate and a reduction in capital expenditures and operating expenses in the second quarter of 2017 as compared to the second in quarter of 2016. General and administrative expense was $49,822 in the second quarter of 2017 compared with $38,303 in the second quarter of 2016, primarily due to increased legal, administrative and audit fees paid in the current period.

        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 June 30, 2017 was $704,100, representing $0.3778 per unit, compared to $145,846, representing $0.0783, for the quarter ended June 30, 2016. Based on 1,863,590 units outstanding for the quarters ended June 2017 and 2016, respectively, the per unit distributions were as follows:

12

        As of June 30, 2017, there were $0 of unreimbursed expenses. 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 June 30, 2017, the Trustee increased the reserve for future unknown contingent liabilities and expenses by $47,840 of royalty income received from BP in June 2017 after the distribution to unitholders had been announced for the month of June 2017. Such royalty income was included in the July 2017 distribution to unitholders. For the three months ended June 30, 2017, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by $82,244 of royalty income received from BP, such that as of June 30, 2017, the reserve for unknown contingent liabilities and expenses was $1,047,840 and is included in cash and short-term investments. 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 June 30, 2017. 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 2.50% return from March 16, 2017 through June 14, 2017 and a 2.75% return from June 15, 2017 through June 30, 2017. 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 $23,037 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 June 30, 2017, such reimbursements totaled $95,897. For the quarter ended June 30, 2016, trustee fees were $108,288. Reimbursements received for the quarter ended June 30, 2016 were $95,897.

Operational Review

Hugoton Field

        Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 49% of the Royalty income of the Trust during the second quarter of 2017.

        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 the second quarter of 2017, the primary purchasers were Kansas Gas Service, Continuum Energy Service, LLC and Enterprise Products Operating, LLC. 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. Overall market prices received for natural gas from Hugoton Royalty Properties were higher for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016.

13

        Royalty income attributable to the Hugoton Royalty Properties increased to $349,915 in the second quarter of 2017 from $65,948 in the second quarter of 2016 primarily due to increases in natural gas and natural gas liquids prices, increased net natural gas and natural gas liquids production volumes and a decrease in capital expenditures and operating costs from the Hugoton Royalty Properties in the second quarter of 2017 compared to the second quarter of 2016. The average price received in the second quarter of 2017 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $3.93 per Mcf and $24.60 per barrel, respectively, as compared to 2.60 per Mcf and $9.83 per barrel, respectively, in the second quarter of 2016. Net production of natural gas attributable to the Hugoton Royalty Properties increased to 65,357 Mcf in the second quarter of 2017 from 19,291 Mcf in the second quarter of 2016. Net production of natural gas liquids attributable to the Hugoton Royalty Properties increased to 3,787 barrels in the second quarter of 2017 from 1,606 barrels in the second quarter of 2016. Actual production volumes from the Hugoton properties increased to 103,985 Mcf of natural gas and decreased to 6,120 barrels of natural gas liquids in the second quarter of 2017 as compared to 90,178 Mcf of natural gas and to 7,514 barrels of natural gas liquids in the second quarter of 2016.

        Capital expenditures attributable to the Hugoton Royalty Properties were $1,023 in the second quarter of 2017, as compared to $2,539 in the second quarter of 2016. Operating costs were $207,824 in the second quarter of 2017, a decrease of approximately 13% as compared to $239,298 in the second quarter of 2016 primarily due to ad valorem taxes.

        On May 11, 2016, Linn Energy, LLC ("Old Linn"), LinnCo, LLC ("LinnCo"), an affiliate of Old Linn, and certain of Old Linn's direct and indirect subsidiaries (collectively with Old Linn and LinnCo, the "Debtors"), filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the "Court"). The Debtors' Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040.

        On January 27, 2017, the Court entered the Order Confirming (I) Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC and (II) Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC, which approved and confirmed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the "Plan"). The Plan became effective on February 28, 2017 (the "Effective Date").

        Pursuant to the Plan, on the Effective Date, all assets of Old Linn (other than equity interests in Linn Acquisition Company, LLC and Berry Petroleum Company, LLC) were conveyed to Linn Energy, Inc. (or a subsidiary thereof), and LinnCo, LLC and Linn Energy, LLC were wound down and liquidated. Subsequent to the effectiveness of the Plan, Linn Energy, Inc. is now the reorganized successor to Old Linn. Under the Plan Supplement, as amended, filed with the Court, the Debtors assumed all executory contracts and unexpired leases with the Trust and Mesa Operating Limited Partnership as the counterparty. Furthermore, pursuant to the Plan, the royalty interests in the Hugoton Royalty Properties owned by the Trust shall be preserved and remain in full force and effect in accordance with the terms of the granting instruments or other governing documents.

14

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. A majority 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 $228,136 during the second quarter of 2017 as compared with Royalty income of $86,981 during the second quarter of 2016. This increase in Royalty income was due primarily to an increase in natural gas, natural gas liquids and oil and condensate prices, increased net production volumes of natural gas, natural gas liquids and oil and condensate and reduced capital expenditures for the second quarter of 2017 compared to the second quarter of 2016, offset in part by an increase in operating costs during the second quarter of 2017 compared to the second quarter of 2016. Net production attributable to the San Juan Basin Royalty Properties located in New Mexico was 73,918 Mcf of natural gas, 4,044 barrels of natural gas liquids and 245 barrels of oil and condensate in the second quarter of 2017, as compared to 43,356 Mcf of natural gas, 2,848 barrels of natural gas liquids and 139 barrels of oil and condensate in the second quarter of 2016. The average price received in the second quarter of 2017 for natural gas, natural gas liquids and oil and condensate sold from the San Juan Basin Royalty Properties located in the State of New Mexico was $2.02 per Mcf, $17.31 per barrel and $38.21 per barrel, respectively, compared to $1.19 per Mcf, $11.03 per barrel and $24.29 per barrel during the same period in 2016. Actual production volumes of natural gas attributable to the San Juan Basin Royalty Properties located in the State of New Mexico decreased to 144,833 Mcf in the second quarter of 2017 from 157,586 Mcf of natural gas for the same period in 2016. Actual production volumes of natural gas liquids attributable to the San Juan Basin Royalty Properties located in the State of New Mexico decreased to 10,636 barrels in the second quarter of 2017 from 11,907 barrels for the same period in 2016. Actual production volumes of oil and condensate attributable to the San Juan Basin Royalty Properties located in the State of New Mexico increased to 471 barrels in the second quarter of 2017 from 421 barrels for the same period in 2016.

        Capital expenditures on these properties were $3,210 in the second quarter of 2017, a decrease of approximately 39% as compared to $5,252 in the second quarter of 2016. Operating costs were $214,518 in the second quarter of 2017, an increase of approximately 8% as compared to $198,586 in the second quarter of 2016. 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 $139,176 during the second quarter of 2017, compared to $30,060 during the second quarter of 2016. This increase in Royalty income was due primarily to higher prices and net production volumes for natural gas, offset in part by an increase in operating expenses in the second quarter of 2017 compared to the second quarter of 2016. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 104,754 Mcf of natural gas during the second quarter of 2017 with 28,629 Mcf of natural gas attributable to the Trust during the second quarter of 2016. The average price received in the second quarter of 2017 for natural gas sold from the San Juan Basin Colorado Properties was $1.32 per Mcf, as compared to average price of $1.02 per Mcf for the second quarter of 2016. Actual production volumes attributable to the San Juan Basin Colorado Properties increased to 126,751 Mcf of natural gas in the second quarter of 2017 from 75,401 Mcf of natural gas for the same period in 2016.

15

        Operating costs on these properties were $31,890 in the second quarter of 2017 as compared to $30,505 in the second quarter of 2016.

Six Months Ended June 30, 2017 and 2016

Financial Review

        The Trust's Royalty income was $1,635,768 for the six months ended June 30, 2017, an increase of approximately 322% as compared to $387,633 for the six months ended June 30, 2016, primarily as a result of increased natural gas, natural gas liquids and oil and condensate prices and net production volumes, reduced capital expenditures and lower operating costs in the first six months of 2017 as compared to the first six months of 2016.

        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 six months ended June 30, 2017 was $1,493,502, representing $0.8014 per unit, compared to $295,330, representing $0.1585 per unit, for the six months ended June 30, 2016.

        As of June 30, 2017, there were $0 of unreimbursed expenses. 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 six months ended June 30, 2017, the Trustee increased the reserve for future unknown contingent liabilities and expenses by (1) $82,244 of royalty income received from BP in March 2017 after the distribution to unitholders had been announced for the month of March 2017 which royalty income was included in the April 2017 distribution to unitholders, and (2) $47,840 of royalty income received from BP in June 2017 after the distribution to unitholders had been announced for the month of June 2017 which royalty income was included in the July 2017 distribution to unitholders. For the six months ended June 30, 2017, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by $82,244 of royalty income received from BP, such that as of June 30, 2017, the reserve for unknown contingent liabilities and expenses was $1,047,840 and is included in cash and short-term investments. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses.

16

        The Trustee was due $237,500 for its services for the six months ended June 30, 2017. The Trust paid $216,576 of this amount to the Trustee, and $20,924 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 a 2.25% return from January 1, 2017 through March 15, 2017, a 2.50% return from March 16, 2017 through June 14, 2017 and a 2.75% return from June 15, 2017 through June 30, 2017. 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 $23,037 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 six months ended June 30, 2017, the Trustee's fees were $216,576 and such reimbursements totaled $191,794. For year to date June 30, 2016, the Trustee's fees were $216,576 and such reimbursements totaled $191,794.

        As of June 30, 2016, there were $812 of unreimbursed expenses. The Trust anticipated receipt of these expense reimbursements by month-end when it published its June distribution press releases on June 18, 2016, and included these amounts in distributions payable and distributable income per unit as of June 30, 2016. During 2011, the Trustee withheld $1.0 million for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. For the six months ended June 30, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expenses by (i) the amounts received during the first quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling $6,738 and (ii) a prior period expense refund received from a vendor in the amount of $101 during the second quarter of 2016. The Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $812. As of June 30, 2016, the reserve for unknown contingent liabilities and expenses was $999,289 and is included in cash and short-term investments. The Trust has subsequently received $812 of the expected expense reimbursement cash receipts as of July 5, 2016, which has increased the reserve for unknown contingent liabilities and expenses.

Operational Review

Hugoton Field

        Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 46% of the Royalty income of the Trust during the six months ended June 30, 2017.

        Royalty income attributable to the Hugoton Royalty Properties increased to $759,585 for the six months ended June 30, 2017 from $145,073 for the same period in 2016 primarily due to higher prices for natural gas and natural gas liquids, an increase in net natural gas and natural gas liquids production volumes, reduced capital expenditures and decreased operating costs from the Hugoton Royalty Properties in the first six months of 2017 compared to the first six months of 2016. The average price received in the first six months of 2017 for natural gas and natural gas liquids sold from the Hugoton field was $3.79 per Mcf and $23.53 per barrel, respectively, compared to $2.77 per Mcf and $9.95 per barrel, respectively, during the same period in 2016. Net production attributable to the Hugoton Royalty Properties increased to 147,095 Mcf of natural gas and 8,562 barrels of natural gas liquids for

17

the six months ended June 30, 2017 as compared to 40,616 Mcf of natural gas and 3,273 barrels of natural gas liquids for the six months ended June 30, 2016. Actual production volumes attributable to the Hugoton Royalty Properties increased to 200,638 Mcf of natural gas and decreased to 11,687 barrels of natural gas liquids in the six months ended June 30, 2017 as compared to 185,769 Mcf of natural gas and 14,836 barrels of natural gas liquids for the same period in 2016.

        Capital expenditures on these properties were $2,276 during the six months ended June 30, 2017 as compared to $2,630 during the six months ended June 30, 2016. Operating costs were $273,851 during the six months ended June 30, 2017, a decrease of approximately 47% as compared to $514,386 during the six months ended June 30, 2016. The decrease in operating costs was due primarily to ad valorem taxes.

San Juan Basin

        Royalty income from the San Juan Basin—New Mexico was $532,161 for the first six months of 2017 compared to $212,501 for the first six months of 2016. The increase in Royalty income was due primarily to higher natural gas, natural gas natural gas liquids and oil and condensate prices, higher net production volumes for natural gas, natural gas liquids and oil and condensate and reduced capital expenditures, offset in part by an increase in operating costs in the first six months of 2017 from the San Juan Basin properties compared to the same period in 2016. The average price received in the first six months of 2017 for natural gas, natural gas liquids and oil and condensate sold from the San Juan Basin Royalty Properties located in the State of New Mexico was $2.31 per Mcf, $16.85 per barrel and $37.87 per barrel, respectively, compared to $1.39 per Mcf, $11.01 per barrel and $25.30 per barrel during the same period in 2016. Net production attributable to the San Juan Basin Royalty located in New Mexico was 159,173 Mcf of natural gas 8,779 barrels of natural gas liquids and 418 barrels of oil and condensate for the six months ended June 30, 2017 as compared to 98,766 Mcf of natural gas, 6,057 barrels of natural gas liquids and 283 barrels of oil and condensate for the six months ended June 30, 2016. Actual production volumes attributable to the San Juan Basin Royalty Properties decreased to 296,766 Mcf of natural gas, 22,236 barrels of natural gas liquids and 777 barrels of oil and condensate in the six months ended June 30, 2017 as compared to 316,105 Mcf of natural gas, 24,430 barrels of natural gas liquids and 809 barrels of oil and condensate for the same period in 2016.

        San Juan Basin—New Mexico capital expenditures were $7,415 during the six months ended June 30, 2017, a decrease of approximately 62% as compared to $19,737 during the six months ended June 30, 2016. Operating costs were $452,407 during the six months ended June 30, 2017, an increase of approximately 6% as compared to $425,285 during the six months ended June 30, 2016.

        Royalty income from the San Juan Basin—Colorado Royalty Properties was $344,021 for the six months ended June 30, 2017, compared to $30,060 during the same period in 2016. The increase in Royalty income was primarily the result of higher prices for natural gas, lower operating costs and increased net natural gas production in the six months ended June 30, 2017 compared to the same period in 2016. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 207,242 Mcf of natural gas during the six months ended June 30, 2017 with 28,432 Mcf of natural gas attributable to the Trust during the same period in 2016. The average price received for the six months ended June 30, 2017 for natural gas sold from the San Juan Basin Colorado Properties was $1.66 per Mcf, compared to $1.05 per Mcf received during the same period in 2016. Actual production volumes attributable to the San Juan Basin—Colorado Royalty Properties increased to

18

248,616 Mcf of natural gas for the six months ended June 30, 2017 as compared to 186,547 Mcf of natural gas for the same period in 2016.

        Operating costs on these properties were $67,302 for the six months ended June 30, 2017 a decrease of approximately 32% as compared to $98,400 in the same period in 2016 due primarily to repairs and recompletions in 2016 compared with 2017.

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 (the "Exchange Act"), is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission'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.

        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

19

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 Interest Owners for information regarding the Royalty Properties" in the Trust's Annual Report on Form 10-K for the year ended December 31, 2016 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, 2016 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.

20

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.

        For a discussion of the Trust's potential risks and uncertainties, please see "Risk Factors" in Item 1A to Part 1 of the Trust's Annual Report on Form 10-K for the year ended December 31, 2016.

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).

21

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: August 14, 2017

        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.

22

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.