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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 September 30, 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

STATEMENTS OF CHANGES IN TRUST CORPUS
(Unaudited)

Note 1—Trust Organization

        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. Substantially all of the San Juan Basin Royalty Properties located in New Mexico are operated by ConocoPhillips. Substantially all of 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 Mellon Trust Company, N.A. (the "Trustee") succeeded JPMorgan Chase Bank, N.A. as Trustee of the Trust. JPMorgan Chase Bank, N.A. is the successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association. The terms of the Mesa Royalty Trust Indenture (the "Trust Indenture") provide, among other things, that:

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

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

        (c)   the Trustee can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge assets of the Trust to secure payment of the borrowings;

        (d)   the Trustee will make cash distributions to the unitholders in January, April, July and October each year as discussed more fully in Note 2;

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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, 2008. Subsequent events have been evaluated through October 9, 2009, the date of the issuance of these financial statements.

        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 are included in the calculation of the monthly distribution amount; 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 later date as the Trustee determines is required to comply with applicable law or stock exchange requirements. However, cash distributions are

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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. The Trustee has been advised by PNR, 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.

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 will incur no federal income tax liability. In addition, there is no state income tax liability for the period.

        The Trustee assumes that some Trust Units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust ("WHFIT") for U.S. federal income tax purposes. Bank of New York Mellon 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.

Note 5—Excess Production Costs

        For the three months ended June 30, 2009, the Trust did not receive any Royalty income associated with the San Juan Basin—Colorado royalty properties operated by BP due to excess production costs incurred during such period. 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. Excess production costs related to the San Juan Basin—Colorado properties were approximately $110,000 as of June 30, 2009. 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.

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Note 6—Recently Issued Pronouncements

        In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:

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commodity prices—economic producibility of reserves and discounted cash flows will be based on a 12-month average commodity price unless contractual arrangements designate the price to be used;



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disclosure of unproved reserves—probable and possible reserves may be disclosed separately on a voluntary basis;



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proved undeveloped reserve guidelines—reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered;



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reserve estimation using new technologies—reserves may be estimated through the use of reliable technology in addition to flow tests and production history; and



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nontraditional resources—the definition of oil and gas producing activities will expand and focus on the marketable product rather than the method of extraction.

        The rules are effective for fiscal years ending on or after December 31, 2009, and early adoption is not permitted. The Trust is currently evaluating the new rules and assessing the impact they will have on its reported oil and gas reserves. The SEC is coordinating with the FASB to obtain the revisions necessary to SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," and SFAS No. 69, "Disclosures about Oil and Gas Producing Activities," to provide consistency with the new rules. In the event that consistency is not achieved in time for companies to comply with the new rules, the SEC may consider delaying the compliance date.

Note 7—Subsequent Events

        PNR has advised the Trustee that it received a proposed assessment from the Kansas Department of Revenue on September 10, 2009, for additional tax, penalty and interest of approximately $4.1 million resulting primarily from the settlement of the lawsuit John Steven Alford and Robert Larrabee, individually and on behalf of a Plaintiff Class v. Pioneer Natural Resources USA, Inc. in early 2007. The portion of the tax assessment net to the Trust is approximately $158,000, which could adversely affect Trust distributions. PNR is currently reviewing the proposed assessment and evaluating possible objections or disputed items. No assurance can be made that any objections or disputed items raised by PNR will be successful.

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

        The following review of the Trust's financial condition and results of operations should be read in conjunction with the financial statements and notes thereto. The discussion of net production attributable to the Hugoton and San Juan properties represents production volumes that are to a large extent hypothetical as the Trust does not own and is not entitled to any specific production volumes. See Note 7 to the financial statements in the Trust's Annual Report on Form 10-K for the year ended December 31, 2008. 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 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, 2008, 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)

As a result of excess production costs incurred in one monthly operating period and then recovered in a subsequent monthly operating period(s), the Royalty income paid to the Trust may not agree to the Trust's royalty interest in the Net Proceeds. Excess production costs related to the San Juan Basin—Colorado properties operated by BP were approximately $110,000 as of June 30, 2009. The excess production costs must be recovered by the Working Interest Owners before any distribution of Royalty income will be made to the Trust.

(3)

Net production volumes attributable to the Royalty are determined by dividing Royalty income by the average sales price received.

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Three Months Ended June 30, 2009 and 2008

Financial Review

        The Trust's Royalty income was $745,374 in the second quarter 2009, a decrease of approximately 79% as compared to $3,476,622 in the second quarter of 2008, primarily as a result of lower natural gas and natural gas liquids prices and reduced production of natural gas and natural gas liquids in the second quarter of 2009 as compared to the second quarter of 2008.

        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 June 30, 2009 was $701,324, representing $.3763 per unit, compared to $3,454,825, representing $1.8539 per unit, for the quarter ended June 30, 2008. Based on 1,863,590 units outstanding for the quarters ended June 30, 2009 and 2008, 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 53% of the Royalty income of the Trust during the second quarter of 2009.

        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 Energy 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

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Hugoton Royalty Properties were significantly lower in the second quarter of 2009 compared to the second quarter of 2008.

        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 since June 1, 2001. PNR extended the contract June 1, 2010. 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 decreased to $393,656 in the second quarter of 2009, as compared to $1,472,388 in the second quarter of 2008. The decrease in Royalty income was primarily due to lower natural gas and natural gas liquid prices. The average price received in the second quarter of 2009 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $3.65 per Mcf and $25.82 per barrel, respectively, compared to $7.53 per Mcf and $63.26 per barrel, respectively, during the same period in 2008. Net production attributable to the Hugoton Royalty was 76,747 Mcf of natural gas and 4,397 barrels of natural gas liquids in the second quarter of 2009 compared to 135,263 Mcf of natural gas and 7,186 barrels of natural gas liquids in the second quarter of 2008. Actual production volumes attributable to the Hugoton properties decreased to 152,172 Mcf of natural and 8,861 barrels of natural gas liquids in the second quarter of 2009 as compared to 166,945 Mcf of natural gas and 8,869 barrels of natural gas liquids for the same period in 2008 as a result of natural production decline.

        Capital expenditures on these properties in the second quarter of 2009 were $20,527, compared to $0 in the second quarter of 2008. The increase in capital expenditures is due to capital well workovers performed during the period. Operating costs were $369,669 in the second quarter of 2009, an increase of approximately 7% as compared to $345,659 in the second quarter of 2008. The increase in operating costs between the three months ended June 30, 2009 and the three months ended June 30, 2008 is due to higher rates charged by service providers.

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 $345,823 during the second quarter of 2009 as compared with $1,811,524 in the second quarter of 2008. The decrease in royalty income was primarily the result of lower natural gas and natural gas liquid prices. The average price received in the second quarter of 2009 for natural gas sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $2.34 per Mcf and $21.69 per barrel, respectively, compared to $7.27 per Mcf and $55.37 per barrel during the same period in 2008. Net production attributable to the San Juan Basin Royalty located in New Mexico was 79,536 Mcf of natural gas and 7,350 barrels of natural gas liquids in the second quarter of 2009 as compared to 141,367 Mcf of natural gas and 14,103 barrels of natural gas liquids in the second quarter of 2008. Actual production volumes attributable to the San Juan Basin properties located in the state of New Mexico increased to 196,565 Mcf of natural gas and 17,962 barrels of natural gas liquids in the second quarter of 2009 as compared to 189,010 Mcf of natural gas and 17,922 barrels of natural gas liquids for

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the same period in 2008. The increase in actual production volume for the three month period ended June 30, 2009 compared to the same period 2008 was due to better run times on conventional gathering.

        Capital expenditures on the San Juan Basin Royalty Properties located in the state of New Mexico were $205,634 in the second quarter of 2009, an increase of approximately 31% as compared to $156,472 in the second quarter of 2008. This increase is due to increased drilling activity in the second quarter of 2009 compared to the second quarter of 2008. Operating costs were $298,099 in the second quarter of 2009, a decrease of approximately 25% as compared to $398,395 in the second quarter of 2008. The decrease in operating expenses for the three month period ended June 30, 2009 compared to the same period in 2008 was due to a reduction in lease inspections and a reduction in well workover expenses.

        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.

        The costs related to the San Juan Basin, Colorado portion of the Fruitland Coal drilling program were recovered in December 2004. However, subsequent earnings after recovery of costs were not remitted to the Trust until December 2006. 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, 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 does not expect to receive any further distributions relating to this issue. 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 $5,895 during the second quarter of 2009, compared to $192,710 during the second quarter of 2008. The decrease in Royalty income was primarily the result of lower natural gas and natural gas liquid prices and an increase in excess production costs. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 2,309 Mcf of natural gas during the second quarter of 2009, compared to 30,653 Mcf of natural gas during the second quarter of 2008. The average price received in the second quarter of 2009 for natural gas sold from the San Juan Basin Colorado Properties was $2.03 compared to $6.29 in the second quarter of 2008. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 37,829 Mcf of natural gas in the second quarter of 2009 as compared to 37,925 Mcf of natural gas for the same period in 2008. Royalty income reported from BP is net of pre-main line production costs. These costs were charged to the Trust in error and as a result the Royalty income for previous periods was reduced. Because Royalty income recorded for a month is the amount computed and paid by BP, the additional Royalties, if any, will not be recorded until received by the Trust.

        Operating costs on these properties were $180,776 in the second quarter of 2009, an increase of approximately 286% as compared to $46,856 in the second quarter of 2008 due to an increase in drilling and workover charges.

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Six Months Ended June 30, 2009 and 2008

Financial Review

        The Trust's Royalty income was $1,880,148 for the six months ended June 30, 2009, a decrease of approximately 70% as compared to $6,361,131 for the six months ended June 30, 2008, primarily as a result of lower natural gas and natural gas liquid prices in the first six months of 2009 as compared to the first six months of 2008.

        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 six months ended June 30, 2009 was $1,787,259, representing $0.9590 per unit, compared to $6,326.850, representing $3.3950 per unit, for the six months ended June 30, 2008.

Operation Review

Hugoton Field

        Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 49% of the Royalty income of the Trust during the six months ended June 30, 2009.

        Royalty income attributable to the Hugoton Royalty Properties decreased to $919,133 for the six months ended June 30, 2009 from $2,664,077 for the same period in 2008 primarily due to decreases in prices for both natural gas and natural gas liquids from the Hugoton Royalty Properties. The average price received in the first six months of 2009 for natural gas and natural gas liquids sold from the Hugoton field was $3.90 per Mcf and $32.58 per barrel, respectively, compared to $6.80 per Mcf and $60.97 per barrel, respectively, during the same period in 2008. Net production attributable to the Hugoton Royalty Properties decreased to 159,605 Mcf of natural gas and 9,106 barrels of natural gas liquids for the six months ended June 30, 2009 as compared to 261,589 Mcf of natural gas and 14,478 barrels of natural gas liquids for the six months ended June 30, 2008. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 322,375 Mcf of natural gas and increased to 18,344 barrels of natural gas liquids in the six months ended June 30, 2009 as compared to 331,422 Mcf of natural gas and 18,328 barrels of natural gas liquids for the same period in 2008. The decrease in natural gas production is a result of natural production decline.

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        The Hugoton capital expenditures were $175,142 during the six months ended June 30, 2009, an increase of approximately 942% as compared to $16,801 during the six months ended June 30, 2008. The increase in the capital expenditures was primarily due to the drilling of two additional wells. Operating costs were $759,040 during the six months ended June 30, 2009, an increase of approximately 10% as compared to $688,979 during the six months ended June 30, 2008 due to higher rates charged by service providers.

San Juan Basin

        The Royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $941,930 for the first six months of 2009 compared to $3,323,031 in the first six months of 2008. The decrease in Royalty income was due primarily to decreased natural gas and natural gas liquid prices in the first six months of 2009 from the San Juan Basin properties. The average price received in the six months ended June 30, 2009 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $3.07 per Mcf and $22.21 per barrel, respectively, compared to $6.42 per Mcf and $56.41 per barrel, respectively, during the same period in 2008. Net production attributable to the San Juan Basin Royalty located in New Mexico was 198,300 Mcf of natural gas and 14,987 barrels of natural gas liquids for the six months ended June 30, 2009 as compared to 278,535 Mcf of natural gas and 26,821 barrels of natural gas liquids for the six months ended June 30, 2008. Actual production volumes attributable to the San Juan Basin Royalty Properties increased to 411,300 Mcf of natural gas and decreased to 32,560 barrels of natural gas liquids in the six months ended June 30, 2009 as compared to 399,670 Mcf of natural gas and 35,342 barrels of natural gas liquids for the same period in 2008. The increase in natural gas production is due to better run times on conventional gathering.

        San Juan-New Mexico capital expenditures were $413,909 during the six months ended June 30, 2009, a decrease of approximately 8% as compared to $450,202 during the six months ended June 30, 2008. This decrease is due to less drilling activity during the six months ended June 30, 2009 when compared to the six months ended June 30, 2008. Operating costs were $630,919 during the six months ended June 30, 2009, a decrease of approximately 23% as compared to $822,924 during the six months ended June 30, 2008. The decrease in operating costs is the result of decreased repair and maintenance activity.

        Royalty income from the San Juan Basin—Colorado Royalty Properties was $19,085 for the six months ended June 30, 2009, compared to $374,023 received during the same period in 2008. The decrease in Royalty income was primarily the result of lower natural gas and natural gas liquid prices and an increase in excess production costs. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 8,069 Mcf of natural gas during the six months ended June 30, 2009 with 66,690 Mcf of natural gas attributable to the Trust during the same period in 2008. The average price received for the six months ended June 30, 2009 for natural gas sold from the San Juan Basin Colorado Properties was $2.47, compared to $5.56 received during the same period in 2008. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 76,130 Mcf of natural gas for the six months ended June 30, 2009 as compared to 77,798 Mcf of natural gas for the same period in 2008.

        Operating costs on these properties were $278,910 for the six months ended June 30, 2009, an increase of approximately 326% as compared to $65,427 in the same period in 2008 due to an increase in drilling charges.

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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;



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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 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 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,

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(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, 2008 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 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. The Trustee has been advised by PNR, 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 on future Royalty income.

Item 1A.    Risk Factors.

        In addition to the risks described in our Annual Report on Form 10-K for the year ended December 31, 2008, we are subject to the following additional risk:

PNR has advised the Trustee that it received a proposed assessment from the Kansas Department of Revenue for additional tax, penalty and interest associated with the Hugoton field, which could adversely affect Trust distributions.

        PNR has advised the Trustee that it received a proposed assessment from the Kansas Department of Revenue on September 10, 2009, for additional tax, penalty and interest of approximately $4.1 million resulting primarily from the settlement of the lawsuit John Steven Alford and Robert Larrabee, individually and on behalf of a Plaintiff Class v. Pioneer Natural Resources USA, Inc. in early 2007. The portion of the tax assessment net to the Trust is approximately $158,000, which could adversely affect Trust distributions. PNR is currently reviewing the proposed assessment and evaluating possible objections or disputed items. No assurance can be made that any objections or disputed items raised by PNR will be successful.

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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 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 is 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: October 9, 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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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

MESA ROYALTY TRUST STATEMENTS OF DISTRIBUTABLE INCOME (Unaudited)
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
MESA ROYALTY TRUST STATEMENTS OF CHANGES IN TRUST CORPUS (Unaudited)
MESA ROYALTY TRUST STATEMENTS OF CHANGES IN TRUST CORPUS (Unaudited)

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

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

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