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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-Q

Commission File Number: 1-7884

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

1-800-852-1422
(Registrant's Telephone Number, Including Area Code)

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        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 o    No ý

        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 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 July 27, 2009—1,863,590 Units of Beneficial Interest were outstanding in Mesa Royalty Trust.

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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.)

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MESA ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(Unaudited)

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

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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 most 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 have been operated by PNR. The San Juan Basin Royalty Properties located in New Mexico are operated by ConocoPhillips. The San Juan Basin Royalty Properties located in Colorado are operated by BP. As used in this report, PNR refers to the 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 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;

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        (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)    PNR, 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.

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, 2007.

        In accordance with the instruments conveying the Royalty, the Working Interest Owners will 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.

        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.

        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 accrue; and

        (d)   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 other day as the Trustee determines is

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required to comply with legal 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 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. PNR has advised the Trustee that the previously reached 2006 settlement in the lawsuit John Steven Alford and Robert Larrabee, individually and on behalf of a Plaintiff Class v. Pioneer Natural Resources USA, Inc., filed in the 26th Judicial District Court, Stevens County, Kansas, was approved in the first quarter of 2007 by the Judge and the case was finalized in April 2007. The plaintiffs in the above noted lawsuit were royalty owners in oil and gas properties located in the Hugoton field, which are owned by PNR, a subsidiary of Pioneer. The plaintiffs sued a predecessor company to PNR asserting various claims relating to alleged improper deductions in the calculation of royalties.

        Under the terms of the agreement, PNR agreed to make cash payments to settle the plaintiffs' claims with respect to production occurring on and before December 31, 2005. PNR also agreed to adjust the manner in which royalty payments to the class members will be calculated for production occurring on and after January 1, 2006.

        Pioneer's portion of the cash payment was approximately $32,700,000. Pioneer agreed to pay the cash portion in two installments. Pioneer advised the Trustee that the portion of the cash payments net to the Trust's interest was approximately $1,000,000 paid on September 30, 2006 and an expected payment of $986,138 payable on September 30, 2007. The approximate $1,000,000 attributable to the Trust paid on September 30, 2006, was deducted from royalty income in the fourth quarter of 2006. In October 2007, Pioneer informed the Trustee that during the course of PNR's analysis of the payments under the terms of the settlement agreement, PNR has now determined that the Trust should not bear any portion of the second installment payment and that PNR should reimburse the Trust for the portion of the first installment payment previously charged to the Trust and paid in September 2006. As a result, PNR included a reimbursement of $1,096,630, including interest in the amount of $110,492, to the distribution made to the Trust in October 2007 which was included in the Trust's fourth quarter receipts, and no portion of the second installment payment was charged to the Trust.

        The Trustee has been advised by ConocoPhillips and BP Amoco 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 of future Royalty income.

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Note 4—Federal 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 will incur no federal income tax liability.

        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. Bank of New York Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, 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.

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 7 to the financial statements in the Trust's Annual Report on Form 10-K for the year ended December 31, 2007. 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, 2007, 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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(1)

Gross Proceeds from natural gas liquids attributable to the Hugoton and San Juan Basin Properties are net of a volumetric in-kind processing fee retained by PNR and ConocoPhillips, respectively.

(2)

Net production volumes attributable to the Royalty are determined by dividing Royalty income by the average sales price received. Net production volumes attributable for Hugoton Royalty for 2007 were not calculated for the 2007 reimbursement from PNR related to the Alford settlement.

Three Months Ended March 31, 2008 and 2007

Financial Review

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        The Trust's Royalty income was $2,884,508 in the first quarter of 2008, an increase of approximately 13% as compared to $2,563,081 in the first quarter of 2007, primarily as a result of higher natural gas liquid prices in the first quarter of 2008 as compared to the first quarter of 2007, offset slightly by lower production volumes for natural gas liquids and increased capital and operating costs during the first quarter of 2008 compared to the first quarter of 2007.

        The distributable income 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. Trust administration expenses are deducted in the computation of distributable income. Distributable income for the quarter ended March 31, 2008 was $2,872,024, representing $1.5411 per unit, compared to $2,572,645, representing $1.3805 per unit, for the quarter ended March 31, 2007. Based on 1,863,590 units outstanding for the quarters ended March 31, 2008 and 2007, respectively, the per unit distributions were as follows:

Operational Review

Hugoton Field

        Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 42% of the Royalty income of the Trust during the first quarter of 2008.

        PNR 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 recently including Greely Gas and Oneok Gas Marketing, Inc. PNR 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 gas from the Hugoton Royalty Properties were significantly higher in the first quarter of 2008 compared to the first quarter of 2007.

        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. This contract has renewed on a year-to-year basis being effective June 1, 2001. PNR extended the contract to June 1, 2008. Pursuant to the Gas Transportation Agreement, WRI 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. This Gas Transportation Agreement was assigned to Kansas Gas Service ("Oneok").

        Royalty income attributable to the Hugoton Royalty increased to $1,191,689 in the first quarter of 2008, from $1,185,761 in the first quarter of 2007 primarily due to increases in natural gas liquids and natural gas prices from the Hugoton Royalty Properties. The average price received in the first quarter of 2008 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $6.05 per Mcf and $58.83 per barrel, respectively, as compared to $5.91 per Mcf and $37.64 per barrel,

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respectively, in the first quarter of 2007. Net production of natural gas attributable to the Hugoton Royalty decreased to 126,326 Mcf in the first quarter of 2008 from 134,714 Mcf in the first quarter of 2007. Net production of natural gas liquids attributable to the Hugoton Royalty decreased from 10,351 barrels in the first quarter of 2007 to 7,288 barrels in the first quarter of 2008. Actual production volumes from the Hugoton properties decreased to 164,476 Mcf of natural gas and 9,459 barrels of natural gas liquids in the first quarter of 2008 as compared to 191,211 Mcf of natural gas and 10,350 barrels of natural gas liquids for the same period in 2007.

        The Hugoton capital expenditures were $17,215 in the first quarter of 2008, an increase of approximately 92% as compared to $8,986 in the first quarter of 2007. Changes in capital activity are attributed to varying needs of capital spending at individual wells. Operating costs were $343,320 in the first quarter of 2008, an increase of approximately 5% as compared to $325,710 in the first quarter of 2007.

        Beginning July 1, 2007 the Hugoton and Panoma fields are considered a single, common source of supply and operated under a single combined Basic Proration Order (BPO). After July 1, 2007 the wells in each of these fields were allowed to produce at their open flow potential and were no longer subject to allowable restrictions. Because no objection was received by December 31, 2007, any and all overage or underage that a well may have accrued were cancelled.

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. The Royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $1,511,505 during the first quarter of 2008 as compared with Royalty income of $1,155,948 in the first quarter of 2007. The increase in Royalty income was due primarily to higher natural gas liquids prices in the first quarter of 2008 compared to the first quarter of 2007 offset in part by increased capital and operating costs. Net production attributable to the San Juan Basin Royalty located in New Mexico was 137,168 Mcf of natural gas and 12,724 barrels of natural gas liquids in the first quarter of 2008, as compared to 111,177 Mcf of natural gas and 15,505 barrels of natural gas liquids in the first quarter of 2007. The average price received in the first quarter of 2008 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $5.66 per Mcf and $57.51 per barrel, respectively, compared to $5.72 per Mcf and $33.54 per barrel during the same period in 2007. Actual production volumes of natural gas attributable to the San Juan Basin properties located in the state of New Mexico decreased to 210,660 Mcf in the first quarter of 2008 as compared to 217,302 Mcf of natural gas for the same period in 2007. Actual production volumes of natural gas liquids attributable to the San Juan Basin properties located in the state of New Mexico increased to 17,416 barrels in the first quarter of 2008 compared to 15,870 barrels for the same period in 2007.

        Capital expenditures on these properties were $293,316 in the first quarter of 2008, an increase of approximately 27% as compared to $230,455 in the first quarter of 2007, primarily due to increased developmental drilling. Operating costs were $424,529 in the first quarter 2008, an increase of approximately 9% as compared to $389,461 in the first quarter of 2007 due to increased repair and maintenance activity.

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        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.

        The costs related to the San Juan Basin, Colorado drilling program were recovered in December 2004. However, subsequent earnings after recovery of costs were not remitted to the Trust until December 2006 and July 2007. The cumulative earnings, including interest on undistributed earnings, reported to the Trust by the working interest owner through November 2006, totaled $1,280,412. In December 2006, BP remitted $978,349 for payment of undistributed earnings from January 2005 through October 2006 and November 2006 earnings for the San Juan properties it operates. In July 2007, Red Willow remitted $159,497 for payment of undistributed earnings from January 2005 through December 2006 for the properties it operates. BP communicated to the Trust these distributions represent all of the previously unpaid revenues. The Trustee is currently investigating the $142,566 difference in the original estimate of unpaid proceeds of $1,280,412 and the payment of $1,137,846. Since Royalty income for the Trust is recorded on a cash basis, the earnings for the year ended December 31, 2006 were not recognized as income until the quarters ended December 31, 2006 and September 30, 2007.

        Royalty income from the San Juan Basin—Colorado Royalty Properties was $181,314 during the first quarter of 2008, compared to $221,372 during the first quarter of 2007. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 36,037 Mcf of natural gas during the first quarter of 2008 with 45,833 Mcf of natural gas attributable to the Trust during the first quarter of 2007. The average price received in the first quarter of 2008 for natural gas sold from the San Juan Basin Colorado Properties was $4.88, as compared to average price of $4.83 for the first quarter of 2007. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 39,873 Mcf of natural gas in the first quarter of 2008 as compared to 49,180 Mcf of natural gas for the same period in 2007.

        Operating costs on these properties were $18,571 in the first quarter of 2008, an increase of approximately 15% as compared to $16,132 in the first quarter of 2007 due to an increase in drilling charges.

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. Natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and the working interest owners. Factors that contribute to price fluctuation include, among others:

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



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worldwide economic conditions;



•

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



•

the supply and price of foreign natural gas;

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the level of consumer demand;



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the price and availability of alternative fuels;



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



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the effect of worldwide energy conservation measures.

        Moreover, government regulations, such as regulation of natural gas transportation 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 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 controls and procedures. The officer acting on behalf of the Trustee concluded that the Trust's disclosure controls and procedures were effective with respect to information by the Trustee and its employees but not effective with respect to information required to be communicated by all of the working interest owners.

        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, 2007 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.

        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

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over, has not evaluated and makes no statement concerning the internal control over financial reporting of the working interest owners.

PART II—OTHER INFORMATION

Item 1.    Legal Proceedings.

        There are no pending legal proceedings to which the Trust is a named party. PNR has advised the Trustee that the previously reached 2006 settlement in the lawsuit John Steven Alford and Robert Larrabee, individually and on behalf of a Plaintiff Class v. Pioneer Natural Resources USA, Inc., filed in the 26th Judicial District Court, Stevens County, Kansas, was approved in the first quarter of 2007 by the Judge and the case was finalized in April 2007. The plaintiffs in the above noted lawsuit were royalty owners in oil and gas properties located in the Hugoton field, which are owned by PNR, a subsidiary of Pioneer. The plaintiffs sued a predecessor company to PNR asserting various claims relating to alleged improper deductions in the calculation of royalties.

        Under the terms of the agreement, PNR agreed to make cash payments to settle the plaintiffs' claims with respect to production occurring on and before December 31, 2005. PNR also agreed to adjust the manner in which royalty payments to the class members will be calculated for production occurring on and after January 1, 2006.

        Pioneer's portion of the cash payment was approximately $32,700,000. Pioneer agreed to pay the cash portion in two installments. Pioneer advised the Trustee that the portion of the cash payments net to the Trust's interest was approximately $1,000,000 paid on September 30, 2006 and an expected payment of $986,138 payable on September 30, 2007. The approximate $1,000,000 attributable to the Trust paid on September 30, 2006, was deducted from royalty income in the fourth quarter of 2006. In October 2007, Pioneer informed the Trustee that during the course of PNR's analysis of the payments under the terms of the settlement agreement, PNR has now determined that the Trust should not bear any portion of the second installment payment and that PNR should reimburse the Trust for the portion of the first installment payment previously charged to the Trust and paid in September 2006. As a result, PNR included a reimbursement of $1,096,630, including interest in the amount of $110,492, to the distribution made to the Trust in October 2007 which was included in the Trust's fourth quarter receipts, and no portion of the second installment payment was charged to the Trust.

        The Trustee has been advised by ConocoPhillips and BP Amoco 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 of future Royalty income.

Item 1A.    Risk Factors.

        There have not been any material changes from risk factors previously disclosed in Item 1A to Part 1 of the Trust's Annual Report on Form 10-K for the year ended December 31, 2007.

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Item 6.    Exhibits.

        (Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. The Bank of New York 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: July 28, 2009

        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

PART I—FINANCIAL INFORMATION

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.

PART II—OTHER INFORMATION

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

Item 6. Exhibits.

SIGNATURES