10-Q

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM                               TO

Commission file number 1-7884

MESA ROYALTY TRUST

(Exact Name of Registrant as Specified in its Charter)

Texas	76-6284806
(State of Incorporation or Organization)	(I.R.S. Employer Identification No.)
JPMorgan Chase Bank, Trustee Institutional Trust Services 700 Lavaca Austin, Texas	78701
(Address of Principal Executive Offices)	(Zip Code)

1-512-479-2562
(Registrant's Telephone Number, Including Area Code)

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

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

        Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

        As of August 14, 2003—1,863,590 Units of Beneficial Interest in Mesa Royalty Trust.

PART I—FINANCIAL INFORMATION

Item 1.    Financial Statements.

MESA ROYALTY TRUST

STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
Royalty income		$	2,751,725		$	1,091,185		$	4,825,994		$	1,994,189
Interest income			7,065			2,626			9,954			4,349
General and administrative expense			(14,519	)		(12,711	)		(24,749	)		(24,508	)
	Distributable income	$	2,744,271		$	1,081,100		$	4,811,199		$	1,974,030
	Distributable income per unit	$	1.4726		$	0.5801		$	2.5817		$	1.0593

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

		June 30, 2003			December 31, 2002
		(Unaudited)
ASSETS
Cash and short-term investments		$	2,737,206		$	1,351,189
Interest receivable			7,065			3,000
Net overriding royalty interest in oil and gas properties			42,498,034			42,498,034
Accumulated amortization			(32,768,114	)		(32,420,602	)
	Total assets	$	12,474,191		$	11,431,621
LIABILITIES AND TRUST CORPUS
Distributions payable		$	2,744,271		$	1,354,189
Trust corpus (1,863,590 units of beneficial interest authorized and outstanding)			9,729,920			10,077,432
	Total liabilities and trust corpus	$	12,474,191		$	11,431,621

(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)

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
Trust corpus, beginning of period		$	9,897,781		$	10,615,151		$	10,077,432		$	10,865,266
	Distributable income		2,744,271			1,081,100			4,811,199			1,974,030
	Distributions to unitholders		(2,744,271	)		(1,081,100	)		(4,811,199	)		(1,974,030	)
	Amortization of net overriding royalty interest		(167,861	)		(238,991	)		(347,512	)		(489,106	)
Trust corpus, end of period		$	9,729,920		$	10,376,160		$	9,729,920		$	10,376,160

(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

        The Mesa Royalty Trust (the "Trust") was created on November 1, 1979 when Mesa Petroleum Co. conveyed to the Trust a 90% net profits overriding royalty interest (the "Royalty") 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 (collectively, the "Royalty Properties"). Mesa Petroleum Co. was the predecessor to Mesa Limited Partnership ("MLP"), the predecessor to MESA Inc. On April 30, 1991, MLP sold its interests in the Royalty Properties located in the San Juan Basin field to ConocoPhillips, successor by merger to Conoco Inc., ("ConocoPhillips"). ConocoPhillips sold the portion of its interests in the San Juan Basin Royalty Properties located in Colorado to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow Production Company (effective April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its interest in the Colorado San Juan Basin Royalty Properties to Amoco Production Company ("Amoco"), a subsidiary of BP Amoco. 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 Amoco. 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 Amoco refers to the operator of the Colorado San Juan Basin Royalty Properties unless otherwise indicated. The terms "working interest owner" and "working interest owners" generally refer to the operators of the Royalty Properties as described above, unless the context in which such terms are used indicates otherwise.

Note 2—Basis of Presentation

        The accompanying unaudited financial information has been prepared by JPMorgan Chase Bank ("Trustee") in accordance with the instructions to Form 10-Q. JPMorgan Chase Bank was formerly known as The Chase Manhattan Bank and is the successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association. 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 2002 Annual Report on Form 10-K.

        The Mesa Royalty Trust Indenture was amended in 1985, the effect of which was an overall reduction of approximately 88.56% in the size of the Trust; therefore, the Trust is now entitled each month to receive 90% of 11.44% of the net proceeds for the preceding month. Generally, net proceeds means the excess of the amounts received by the working interest owners from sales of oil and gas from the Royalty Properties over operating and capital costs incurred.

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        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;

        (d)   Amortization of the net overriding royalty interests, which is calculated on a unit-of-production basis, is charged directly to trust corpus since such amount does not affect distributable income; and

        (e)   Distributions payable are determined on a monthly basis and are payable to unitholders of record as of the last business day of each month or such other day as the Trustee determines is 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 Royalty income is thought to be the most meaningful because distributions to the unitholders for a month are based on net cash receipts for such month. However, it will differ from the basis used for financial statements prepared in accordance with accounting principles accepted in the United States of America because under these accounting 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.

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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 Form 10-K. Any discussion of "actual" production volumes represents the hydrocarbons that were produced from the properties in which the Trust has an overriding royalty interest.

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 have been 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 Form 10-K, including under the section "Business—Principal Trust Risk Factors". All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements.

SUMMARY OF ROYALTY INCOME AND AVERAGE PRICES

        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 Royalty conveyance. The following unaudited summary illustrates the net effect of the components of the actual Royalty computation for the periods indicated:

		Three Months Ended June 30,
		2003						2002
		Natural Gas			Oil, Condensate and Natural Gas Liquids			Natural Gas			Oil, Condensate and Natural Gas Liquids
The Trust's proportionate share of Gross Proceeds(1)		$	3,158,662		$	669,296		$	1,511,497		$	440,350
Less the Trust's proportionate share of:
	Capital costs recovered(2)		(144,819	)		—			(104,360	)		—
	Operating costs		(839,483	)		(85,933	)		(677,687	)		(73,373	)
	Interest on cost carryforward		(5,998	)		—			(5,242	)		—
Royalty income		$	2,168,362		$	583,363		$	724,208		$	366,977
Average sales price		$	5.76		$	25.22		$	2.28		$	13.84
			(Mcf)			(Bbls)			(Mcf)			(Bbls)
Net production volumes attributable to the Royalty(3)			376,703			23,129			317,454			26,508

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		Six Months Ended June 30,
		2003						2002
		Natural Gas			Oil, Condensate and Natural Gas Liquids			Natural Gas			Oil, Condensate and Natural Gas Liquids
The Trust's proportionate share of Gross Proceeds(1)		$	5,442,617		$	1,251,073		$	3,151,617		$	891,850
Less the Trust's proportionate share of:
	Capital costs recovered(2)		(147,843	)		—			(496,569	)		—
	Operating costs		(1,546,202	)		(161,811	)		(1,400,940	)		(141,627	)
	Interest on cost carryforward		(11,840	)		—			(10,142	)		—
Royalty income		$	3,736,732		$	1,089,262		$	1,243,966		$	750,223
Average sales price		$	4.77		$	22.69		$	2.33		$	13.68
			(Mcf)			(Bbls)			(Mcf)			(Bbls)
Net production volumes attributable to the Royalty(3)			783,187			48,000			534,824			54,860

(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)

Capital costs recovered represents capital costs incurred during the current or prior periods to the extent that such costs have been recovered by the working interest owners from current period Gross Proceeds. Cost carryforward represents capital costs incurred during the current or prior periods which will be recovered from future period Gross Proceeds. The cost carryforward resulting from the Fruitland Coal drilling program was $322,626 and $304,208 at June 30, 2003 and June 30, 2002, respectively. The cost carryforward at June 30, 2003 and June 30, 2002 relate solely to the San Juan Basin Colorado properties.

(3)

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

Three Months Ended June 30, 2003 and 2002

        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, 2003 was $2,744,271, representing $1.4726 per unit, compared to $1,081,100, representing $0.5801 per unit, for the quarter ended June 30, 2002. Based on 1,863,590 units outstanding for the quarters ended June 30, 2003 and 2002, respectively, the per unit distributions were as follows:

	2003		2002
April	$	0.4151	$	0.1720
May		0.4808		0.1941
June		0.5767		0.2140
	$	1.4726	$	0.5801

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Hugoton Field

        Natural gas and natural gas liquids from the Hugoton field and attributable to the Royalty accounted for approximately 60% of the Royalty income of the Trust during the second quarter of 2003.

        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 including Tenaska, Greely Gas, Oneok Gas Marketing Inc. and Amoco. 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. Overall market prices received for natural gas from the Hugoton Royalty Properties were higher in the second quarter of 2003 compared to the second quarter of 2002.

        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 been continued in effect on a year-to-year basis since June 1, 2000. PNR has extended the contract to June 1, 2004. Pursuant to the Gas Transportation Agreement, WRI has 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 has been assigned to Kansas Gas Service ("Oneok").

        Royalty income attributable to the Hugoton Royalty Properties increased to $1,658,428 in the second quarter of 2003, as compared to $613,419 in the second quarter of 2002 primarily due to higher prices received for production of natural gas and natural gas liquids from the Hugoton Royalty Properties. The average price received in the second quarter of 2003 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $6.41 per Mcf and $26.22 per barrel, respectively, compared to $2.25 per Mcf and $11.94 per barrel during the same period in 2002. Net production attributable to the Hugoton Royalty was 206,837 Mcf of natural gas and 12,685 barrels of natural gas liquids in the second quarter of 2003 compared to 193,256 Mcf of natural gas and 14,958 barrels of natural gas liquids in the second quarter of 2002. Actual production volumes attributable to the Hugoton properties decreased to 257,696 Mcf of natural gas and 12,686 barrels of natural gas liquids in the second quarter of 2003 as compared to 297,031 Mcf of natural gas and 14,954 barrels of natural gas liquids for the same period in 2002 as a result of natural production decline.

        Allowable rates of production in the Hugoton field are set by the Kansas Corporation Commission (the "KCC") based on the level of market demand. The KCC has set the Hugoton field allowable for the period April 1, 2003 through September 30, 2003, at 126.4 Bcf of gas, compared with 141.4 Bcf of gas during the same period last year.

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. Royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $1,093,297 during the second quarter of 2003 as compared with $477,766 in the second quarter of 2002. The increase in Royalty income was due primarily to increased natural gas and natural gas liquids prices in the second quarter of 2003 as compared to the second quarter of 2002. No Royalty income was received from Amoco with respect to the San Juan Basin Royalty Properties located in the state of Colorado in either of the second quarters of 2003 or 2002, as costs associated with the Fruitland Coal drilling program on such properties have not been fully recovered. Net production attributable to the San Juan Basin Royalty was 169,866 Mcf of natural gas and 10,444 barrels of natural gas liquids in the second quarter of 2003 as compared to 124,198 Mcf of natural gas and 11,550 barrels of natural gas liquids in the second quarter of 2002. The average price received in the second quarter of 2003 for natural gas sold from the San Juan Basin Royalty Properties was $4.96 per Mcf and $24.01 per barrel, respectively, compared to $2.33 per Mcf and $16.31 per barrel during

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the same period in 2002. Actual production volumes attributable to the San Juan Basin properties decreased to 280,976 Mcf of natural gas and 14,024 barrels of natural gas liquids in the second quarter of 2003 as compared to 346,680 Mcf of natural gas and 16,050 barrels of natural gas liquids for the same period in 2002 as a result of natural production decline.

        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 San Juan Basin New Mexico reserves represent approximately 58% of the Trust's estimated reserves as of December 31, 2002. Substantially all of the natural gas produced from the San Juan Basin is currently being sold on the spot market. The San Juan Basin Royalty Properties located in Colorado account for less than 5% of the Trust's reserves.

        No distributions related to the Colorado portion of the San Juan Basin Royalty have been made since 1990, as the costs of the Fruitland Coal drilling in Colorado have not yet been recovered.

Six Months Ended June 30, 2003 and 2002

        Distributable income increased to $4,811,199 for the six months ended June 30, 2003 from $1,974,030 for the same period in 2002.

Hugoton Field

        Royalty income attributable to the Hugoton Royalty Properties increased to $2,865,824 for the six months ended June 30, 2003 from $1,269,525 for the same period in 2002 primarily due to higher natural gas and natural gas liquids average prices received. The average price received in the first six months of 2003 for natural gas and natural gas liquids sold from the Hugoton field was $5.05 per Mcf and $22.57 per barrel, compared to $2.29 per Mcf and $12.87 per barrel during the same period in 2002. Net production attributable to the Hugoton Royalty Properties increased to 447,249 Mcf of natural gas and 26,904 barrels of natural gas liquids for the six months ended June 30, 2003 as compared to 374,687 Mcf of natural gas and 31,973 barrels of natural gas liquids for the six months ended June 30, 2002. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 542,324 Mcf of natural gas and 26,909 barrels of natural gas liquids in the six months ended June 30, 2003 as compared to 620,698 Mcf of natural gas and 31,967 barrels of natural gas liquids for the same period in 2002 as a result of natural production decline.

San Juan Basin

        Royalty income attributable to the New Mexico San Juan Basin Royalty Properties increased to $1,960,170 for the first six months of 2003 compared to $724,664 in the first six months of 2002. The average price received in the six months ended June 30, 2003 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties was $4.40 per Mcf and $22.85 per barrel, respectively, compared to $2.41 per Mcf and $14.80 per barrel during the same period in 2002. Net production attributable to the San Juan Basin Royalty Properties increased to 335,938 Mcf of natural gas and 21,096 barrels of natural gas liquids for the six months ended June 30, 2003 as compared to 160,138 Mcf of natural gas and 22,887 barrels of natural gas liquids for the six months ended June 30, 2002. No Royalty income was received from San Juan Basin Royalty Properties located in Colorado for the six months ended June 30, 2003 and 2002, as costs associated with Fruitland Coal drilling on such properties have not been fully recovered. Actual production volumes attributable to the San Juan Basin Royalty Properties decreased to 574,141 Mcf of natural gas and 28,175 barrels of natural gas liquids in the six months ended June 30, 2003 as compared to 690,836 Mcf of natural gas and 32,464 barrels of natural gas liquids for the same period in 2002 as a result of natural production decline.

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Item 3.    Quantitative and Qualitative Disclosure About Market Risk.

        The Trust does not utilize market sensitive instruments, however, see the discussion of marketing by the working interest owners above.

Item 4.    Legal Proceedings.

        There are no pending legal proceedings to which the Trust is a named party. However, PNR has informed the Trust that PNR is party to a 1993 class action lawsuit filed in the 26th Judicial District court of Stevens County, Kansas by two classes of royalty owners (one for each of PNR's gathering systems connected to PNR's Satanta gas plant). The case was relatively inactive for several years. In early 2000, the plaintiffs amended their pleadings to add claims. The lawsuit now has two material claims: (1) that the plaintiffs were improperly charged for a proportionate share of compression expenses incurred by PNR downstream of its wells and upstream of its Satanta gas plant and (2) that plaintiffs are entitled to 100% of the value of the helium extracted at PNR's Satanta gas plant. If the plaintiffs were to prevail on the above claims in their entirety, within what the court has ruled to be the applicable limitations period, PNR believes it is possible that PNR's liability could reach $32.5 million, plus prejudgment interest and attorneys' fees. The Trust's share of this amount would be approximately $1.6 million, plus prejudgment interest and attorneys' fees.

        PNR believes the compression expenses charged to the plaintiffs represent the plaintiffs' pro-rata share of post-production expenses incurred to add value to gas which was marketable at the well and, therefore, were expenses properly charged to plaintiffs under Kansas law. PNR has also vigorously defended against the plaintiffs' claims to 100% of the value of the helium extracted and believes that it has properly accounted to the plaintiffs for its helium production.

        The case was tried to the Court without a jury in December 2001. No judgment or findings have been entered. Arguments for judgment were presented in the second quarter of 2002. Judgment could be entered at any time. However, it is anticipated that the losing side, whichever that might be, would appeal. Entry of a final judgment adverse to PNR would reduce any amount available for distribution to the Trust for the period in which liability is recorded and during periods required for PNR to recoup any additional amounts.

Item 5.    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 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 is accumulated and communicated by the working interest owners to the Trustee 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 date of this report, the Trustee carried out an evaluation of the Trustee's disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the controls and procedures are effective, while noting certain limitations on disclosure controls and procedures as set forth below.

        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, there are certain weaknesses that are not subject to change or modification by the Trustee. The contractual

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limitations creating potential weaknesses in disclosure controls and procedures may be deemed to include:

•

The working interest owners alone control (i) historical operating data, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, the effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures, (iii) geological data relating to reserves, as well as the reserve report that contains projected production, operating expenses and capital expenses, and (iv) information relating to projected production. The Trustee does not control this information and relies entirely on the working interest owners to provide accurate and timely information when requested for use in the Trust's periodic reports.



•

Under the terms of the Trust Agreement, the Trustee is entitled to rely, and in fact relies, on certain experts in good faith, including the independent auditors with respect to audits of financial data provided by the working interest owners. Other than contracting independent auditors and reviewing information supplied by the working interest owners, the Trustee makes no independent or direct verification of this financial information. While the Trustee has no reason to believe its reliance upon experts is unreasonable, this reliance on experts and limited access to information may be viewed as a weakness.

        The Trustee does not intend to expand its responsibilities beyond those permitted or required by the Trust Indenture and those required under applicable law.

        Changes in Internal Controls.    To the knowledge of the Trustee, there have been no significant changes in the Trustee's internal controls or in other factors that could significantly affect the Trustee's internal controls subsequent to the date the Trustee completed its evaluation. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal controls of the working interest owners.

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PART II—OTHER INFORMATION

Item 6.    Exhibits and Reports on Form 8-K

(a)

Exhibits

        (Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. JPMorgan Chase Bank 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.)

			SEC File or Registration Number	Exhibit Number
4(a)	*	Mesa Royalty Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated November 1, 1979	2-65217	1	(a)
4(b)	*	Overriding Royalty Conveyance between Mesa Petroleum Co. and Texas Commerce Bank, as Trustee, dated November 1, 1979	2-65217	1	(b)
4(c)	*	First Amendment to the Mesa Royalty Trust Indenture dated as of March 14, 1985 (Exhibit 4(c) to Form 10-K for year ended December 31, 1984 of Mesa Royalty Trust)	1-7884	4	(c)
4(d)	*	Form of Assignment of Overriding Royalty Interest, effective April 1, 1985, from Texas Commerce Bank National Association, as Trustee, to MTR Holding Co. (Exhibit 4(d) to Form 10-K for year ended December 31, 1984 of Mesa Royalty Trust)	1-7884	4	(d)
4(e)	*	Purchase and Sale Agreement, dated March 25, 1991, by and among Mesa Limited Partnership, Mesa Operating Limited Partnership and Conoco, as amended on April 30, 1991 (Exhibit 4(e) to Form 10-K for year ended December 31, 1991 of Mesa Royalty Trust)	1-7884	4	(e)
31		Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32		Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b)

Reports on Form 8-K

        Current reports on Form 8-K were filed with the Securities and Exchange Commission on May 21, 2003, June 24, 2003, and July 21, 2003.

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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.

MESA ROYALTY TRUST
By:	/S/  JPMORGAN CHASE BANK, Trustee
By:	/s/  MIKE ULRICHMike Ulrich Vice President & Trust Officer

Date: August 14, 2003

        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
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 NOTES TO FINANCIAL STATEMENTS (Unaudited)
SUMMARY OF ROYALTY INCOME AND AVERAGE PRICES
PART II—OTHER INFORMATION
SIGNATURES

EX-31

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Exhibit 31

CERTIFICATION

I, Mike Ulrich, certify that:

        1.     I have reviewed this quarterly report on Form 10-Q of Mesa Royalty Trust, for which JPMorgan Chase Bank acts as Trustee;

        2.     Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

        3.     Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this quarterly report;

        4.     I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

        a)    designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

        b)    evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

        c)     disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

        5.     I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors:

        a)    all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

        b)    any fraud, whether or not material, that involves any persons who have a significant role in the registrant's internal control over financial reporting.

In giving the foregoing certifications in paragraphs 4 and 5, I have relied to the extent I consider reasonable on information provided to me by the working interest owners.

Date: August 14, 2003 /s/ MIKE ULRICHMike Ulrich,
Vice President and Trust Officer
JPMorgan Chase Bank

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CERTIFICATION

EX-32

Exhibit 32

August 14, 2003

Via EDGAR

Securities and Exchange Commission
Judiciary Plaza
450 Fifth Street, N.W.
Washington, D.C. 20549

Re:

Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Ladies and Gentlemen:

In connection with the Quarterly Report of Mesa Royalty Trust (the "Trust") on Form 10-Q for the quarterly period ended June 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

        (1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

        (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

The above certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and is not being filed as part of the Form 10-Q or as a separate disclosure document.

JPMorgan Chase Bank, Trustee for Mesa Royalty Trust
By:	/s/ Mike Ulrich     Mike Ulrich      Vice President and Trust Officer