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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-Q

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MESA ROYALTY TRUST
(Exact Name of Registrant as Specified in its Charter)

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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 ý

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

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

         As of November 6, 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 DISTRIBUTABLE INCOME
(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;

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        (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)    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 November 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

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        (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 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 nine months ended September 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 $50,000 as of September 30, 2009. The excess

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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.

Note 6—Tax Assessment

        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 has submitted a written response objecting to the proposed assessment. No assurance can be made that any objections or disputed items raised by PNR will be successful.

Note 7—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 SEC rules and proposed FASB Accounting Standards Update 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 U.S. GAAP concerning financial accounting and reporting by oil and gas producing companies and disclosures about oil and gas producing activities to provide consistency with the new rules. During September 2009, the FASB issued an exposure draft of a proposed Accounting Standards Update "Oil and Gas Reserves Estimation and Disclosures." The proposed update would amend existing standards to align the reserves calculation and disclosure requirements in the SEC rules. As proposed, the update would be effective for annual reporting periods ending on or after December 31, 2009, and would be applied prospectively as a change in estimate.

        In June 2009, the FASB established the FASB Accounting Standards Codification (Codification), which officially commenced July 1, 2009, to become the source of authoritative US GAAP recognized

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by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative US GAAP for SEC registrants. Generally, the Codification is not expected to change US GAAP. All other accounting literature excluded from the Codification will be considered nonauthoritative. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We adopted the new standards for our quarter ending September 30, 2009. All references to authoritative accounting literature are now referenced in accordance with the Codification.

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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Three Months Ended September 30, 2009 and 2008

Financial Review

        The Trust's Royalty income was $923,220 in the third quarter 2009, a decrease of approximately 80% as compared to $4,535,119 in the third quarter of 2008, primarily as a result of lower natural gas and natural gas liquids prices in the third quarter of 2009 as compared to the third 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 (if any). Trust administration expenses are deducted in the computation of distributable income. Distributable income for the quarter ended September 30, 2009 was $862,601, representing $.4629 per unit, compared to $4,510,158, representing $2.4201 per unit, for the quarter ended September 30, 2008. Based on 1,863,590 units outstanding for the quarters ended September 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 38% of the Royalty income of the Trust during the third 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 Hugoton Royalty Properties were significantly lower in the third quarter of 2009 compared to the third quarter of 2008.

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        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 through 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 $352,427 in the third quarter of 2009, as compared to $1,844,490 in the third 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 third quarter of 2009 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $3.21 per Mcf and $28.11 per barrel, respectively, compared to $9.73 per Mcf and $65.50 per barrel, respectively, during the same period in 2008. Net production attributable to the Hugoton Royalty was 72,824 Mcf of natural gas and 4,221 barrels of natural gas liquids in the third quarter of 2009 compared to 137,627 Mcf of natural gas and 7,723 barrels of natural gas liquids in the third quarter of 2008. Actual production volumes attributable to the Hugoton properties decreased to 154,594 Mcf of natural and 8,909 barrels of natural gas liquids in the third quarter of 2009 as compared to 164,581 Mcf of natural gas and 9,235 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 third quarter of 2009 were $24,804, compared to $0 in the third quarter of 2008. The increase in capital expenditures is due to 2 new wells being drilled in late 2008. Operating costs were $369,207 in the third quarter of 2009, a decrease of approximately 2% as compared to $375,270 in the third quarter of 2008.

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 $570,562 during the third quarter of 2009 as compared with $2,416,644 in the third 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 third quarter of 2009 for natural gas sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $2.17 per Mcf and $26.97 per barrel, respectively, compared to $8.85 per Mcf and $65.90 per barrel during the same period in 2008. Net production attributable to the San Juan Basin Royalty located in New Mexico was 133,333 Mcf of natural gas and 10,441 barrels of natural gas liquids in the third quarter of 2009 as compared to 176,766 Mcf of natural gas and 12,939 barrels of natural gas liquids in the third quarter of 2008. Actual production volumes attributable to the San Juan Basin properties located in the state of New Mexico increased to 225,179 Mcf of natural gas and 17,758 barrels of natural gas liquids in the third quarter of 2009 as compared to 224,779 Mcf of natural gas and 16,486 barrels of natural gas liquids for the same period in 2008. The increase in actual production volume for the three month period ended September 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 $133,574 in the third quarter of 2009, a decrease of approximately 20% as compared to $166,650

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in the third quarter of 2008. This decrease is due to decreased drilling activity in the third quarter of 2009 compared to the third quarter of 2008. Operating costs were $262,663 in the third quarter of 2009, a decrease of approximately 47% as compared to $491,761 in the third quarter of 2008. The decrease in operating expenses for the three month period ended September 30, 2009 compared to the same period in 2008 was due to a reduction in lease inspections and a reduction in well workover expenses.

        Royalty income from the San Juan Basin—Colorado Royalty Properties was $231 during the third quarter of 2009, compared to $273,985 during the third quarter of 2008. The decrease in Royalty income was primarily the result of lower natural gas prices and an increase in excess production costs. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 111 Mcf of natural gas during the third quarter of 2009, compared to 34,283 Mcf of natural gas during the third quarter of 2008. The average price received in the third quarter of 2009 for natural gas sold from the San Juan Basin Colorado Properties was $2.09 compared to $8.28 in the third quarter of 2008. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 37,109 Mcf of natural gas in the third quarter of 2009 as compared to 38,807 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 $68,262 in the third quarter of 2009, an increase of approximately 44% as compared to $47,445 in the third quarter of 2008 due to an increase in drilling and workover charges.

Nine Months Ended September 30, 2009 and 2008

Financial Review

        The Trust's royalty income was $2,803,368 for the nine months ended September 30, 2009, a decrease of approximately 74% as compared to $10,896,240 for the nine months ended September 30, 2008, primarily as a result of lower natural gas and natural gas liquid prices in the first nine months of 2009 as compared to the first nine 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 nine months ended September 30, 2009 was $2,649,860, representing $1.4219 per unit,

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compared to $10,836,999, representing $5.8151 per unit, for the nine months ended September 30, 2008.

Operation Review

Hugoton Field

        Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 45% of the Royalty income of the Trust during the nine months ended September 30, 2009.

        Royalty income attributable to the Hugoton Royalty Properties decreased to $1,271,561 for the nine months ended September 30, 2009 from $4,508,561 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 nine months of 2009 for natural gas and natural gas liquids sold from the Hugoton field was $3.67 per Mcf and $31.12 per barrel, respectively, compared to $7.77 per Mcf and $62.49 per barrel, respectively, during the same period in 2008. Net production attributable to the Hugoton Royalty Properties decreased to 233,304 Mcf of natural gas and 13,346 barrels of natural gas liquids for the nine months ended September 30, 2009 as compared to 399,141 Mcf of natural gas and 22,193 barrels of natural gas liquids for the nine months ended September 30, 2008. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 476,972 Mcf of natural gas and 27,243 barrels of natural gas liquids in the nine months ended September 30, 2009 as compared to 496,003 Mcf of natural gas and 27,563 barrels of natural gas liquids for the same period in 2008. The decrease in natural gas production is a result of natural production decline.

        The Hugoton capital expenditures were $199,945 during the nine months ended September 30, 2009, an increase of approximately 6680% as compared to $2,949 during the nine months ended September 30, 2008. The increase in the capital expenditures was primarily due to the drilling of two additional wells. Operating costs were $1,128,247 during the nine months ended September 30, 2009, an increase of approximately 6% as compared to $1,064,250 during the nine months ended September 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 $1,512,491 for the first nine months of 2009 compared to $5,739,675 in the first nine months of 2008. The decrease in royalty income was due primarily to decreased natural gas and natural gas liquid prices. The average price received in the nine months ended September 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 $2.75 per Mcf and $23.89 per barrel, respectively, compared to $7.32 per Mcf and $59.82 per barrel, respectively, during the same period in 2008. Net production attributable to the San Juan Basin Royalty located in New Mexico was 326,116 Mcf of natural gas and 25,718 barrels of natural gas liquids for the nine months ended September 30, 2009 as compared to 455,299 Mcf of natural gas and 39,765 barrels of natural gas liquids for the nine months ended September 30, 2008. Actual production volumes attributable to the San Juan Basin Royalty Properties increased to 636,480 Mcf of natural gas and decreased to 50,319 barrels of natural gas liquids in the nine months ended September 30, 2009 as compared to 624,450 Mcf of natural gas and 51,824 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.

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        San Juan-New Mexico capital expenditures were $547,483 during the nine months ended September 30, 2009, a decrease of approximately 11% as compared to $616,854 during the nine months ended September 30, 2008. This decrease is due to less drilling activity during the nine months ended September 30, 2009 when compared to the nine months ended September 30, 2008. Operating costs were $893,582 during the nine months ended September 30, 2009, a decrease of approximately 32% as compared to $1,314,683 during the nine months ended September 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 $19,316 for the nine months ended September 30, 2009, compared to $648,004 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 7,804 Mcf of natural gas during the nine months ended September 30, 2009 with 98,829 Mcf of natural gas attributable to the Trust during the same period in 2008. The average price received for the nine months ended September 30, 2009 for natural gas sold from the San Juan Basin Colorado Properties was $2.35, compared to $6.53 received during the same period in 2008. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 113,329 Mcf of natural gas for the nine months ended September 30, 2009 as compared to 116,605 Mcf of natural gas for the same period in 2008.

        Operating costs on these properties were $297,285 for the nine months ended September 30, 2009, an increase of approximately 163% as compared to $112,870 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;



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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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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 DISTRIBUTABLE INCOME (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.