MESA ROYALTY TRUST/TX - Quarter Report: 2005 June (Form 10-Q)

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15() OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2005
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15() 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	(I.R.S. Employer
or Organization)	Identification No.)
JPMorgan Chase Bank, N.A., Trustee
Institutional Trust Services
700 Lavaca
Austin, Texas	78701
(Address of Principal Executive Offices)	(Zip Code)

1-800-852-1422 / 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 x No o

Indicate by a check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x 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 9, 2005—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,
	2005			2004			2005			2004
Royalty income	$	2,244,561		$	2,187,806		$	4,783,802		$	4,349,832
Interest income	3,545			2,429			7,160			4,627
General and administrative expense	(19,608		)	(19,195		)	(39,612		)	(29,819		)
Distributable income	$	2,228,498		$	2,171,040		$	4,751,350		$	4,324,640
Distributable income per unit	$	1.1958		$	1.1650		$	2.5496		$	2.3206
Units outstanding	1,863,590			1,863,590			1,863,590			1,863,590

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
(Unaudited)

	June 30, 2005			December 31, 2004
ASSETS
Cash and short-term investments	$	2,224,953		$	2,302,407
Interest receivable	3,545			2,835
Net overriding royalty interest in oil and gas properties	42,498,034			42,498,034
Accumulated amortization	(33,728,794		)	(33,480,967		)
Total assets	$	10,997,738		$	11,322,309
LIABILITIES AND TRUST CORPUS
Distributions payable	$	2,228,498		$	2,305,242
Trust corpus (1,863,590 units of beneficial interest authorized and outstanding)	8,769,240			9,017,067
Total liabilities and trust corpus	$	10,997,738		$	11,322,309

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Trust corpus, beginning of period	$	8,892,121		$	9,409,988		$	9,017,067		$	9,547,692
Distributable income	2,228,498			2,171,040			4,751,350			4,324,640
Distributions to unitholders	(2,228,498		)	(2,171,040		)	(4,751,350		)	(4,324,640		)
Amortization of net overriding royalty interest	(122,881		)	(130,592		)	(247,827		)	(268,296		)
Trust corpus, end of period	$	8,769,240		$	9,279,396		$	8,769,240		$	9,279,396

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

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 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. All of the San Juan Basin Royalty Properties located in New Mexico and a few wells located in Southwest Colorado near the New Mexico border, are operated by ConocoPhillips. Substanitally all of 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.

Unless sooner terminated, the Trust Agreement provides that the Trust will terminate in the event that the net revenues fall below $250,000 for two successive years. Net revenues are calculated as royalty and interest income after administrative expenses of the Trust. The Trust may be terminated at any time by a vote of unitholders owning a majority of the Units. The Trust may also be terminated at the expiration of twenty-one years after the death of the last to die of all of the descendants living at the date of execution of this Trust Agreement of Joseph P. Kennedy, late father of the late President of the United States, John F. Kennedy.

Upon termination of the Trust, the Trustee shall sell for cash all the assets. The Trustee shall as promptly as possible distribute the proceeds of any such sales and any other cash according to the respective interests and rights of the unitholders, after paying, satisfying and discharging all the liabilities of

the Trust, or, when necessary, setting up reserves in such amounts as Trustee in its discretion deems appropriate for contingent liabilities.

In the event that any property which the Trustee is required to sell is not sold by the Trustee within three years after the termination of the Trust, the Trustee shall cause such property to be sold at public auction to the highest cash bidder. Notice of such sale by auction shall be mailed at least thirty days prior to such sale to each unitholder at his address as it appears upon the books of the Trustee.

Note 2—Basis of Presentation

The accompanying unaudited financial information has been prepared by JPMorgan Chase Bank, N.A., (“Trustee”) in accordance with the instructions to Form 10-Q. JPMorgan Chase Bank, N.A. 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 2004 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.

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;

(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 distributable 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.

Note 3—PNR Legal Proceedings

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 and it now contains two material claims. First, the plaintiffs assert that they were improperly charged expenses (primarily field compression), which are a “cost of production”, and for which the plaintiffs, as royalty owners, are not responsible. Second, the plaintiffs claim they are entitled to 100 percent of the value of the helium extracted at PNR’s Satanta gas plant. If the plaintiffs were to prevail on the above two claims in their entirety, it is possible that PNR’s liability (both for periods covered by the lawsuit and from the last date covered by the lawsuit to the present—because the deductions continue to be taken and the plaintiffs continue to be paid for a royalty share of the helium) could reach $33.0 million related to the cost of production claims and approximately $41.0 million related to the helium claims, plus prejudgment interest. PNR has advised that the Trust’s share of this amount could exceed $2.6 million for the cost of production claim and $2.8 million for the helium claim.

PNR does not believe the costs it has deducted are a “cost of production”. The costs being deducted are post-production costs incurred to transport the gas to PNR’s Satanta gas plant for processing, where the valuable hydrocarbon liquids and helium are extracted from the gas. The plaintiffs benefit from these extractions, and PNR believes that charging the plaintiffs with their proportionate share of these transportation and processing expenses is consistent with Kansas law and with the parties’ agreements.

PNR has also vigorously defended against plaintiffs’ claims to 100 percent of the value of the helium extracted, and believes that in accordance with applicable law, it has properly accounted to the plaintiffs for their fractional royalty share of the helium under the specified royalty clauses of the respective oil and gas leases.

The factual evidence in the case was presented to the 26th Judicial District Court without a jury in December 2001. Oral arguments were heard by the court in April 2002, and although the court has not yet entered a judgment or findings, it could do so at any time. PNR strongly denies the existence of any material underpayment to the plaintiffs and believes it presented strong evidence at trial to support its positions.

However, either through a negotiated settlement or court ruling, PNR could have to pay some part of the cost of production claim. PNR has not withheld any amounts from Royalty income payable to the Trust. Accordingly, the amount of any resulting liability could have a material adverse effect on the Trust’s Royalty income and distributable income for the quarterly reporting period in which such liability is recorded and subsequent reporting periods until the Trust’s share of such amounts are recouped by PNR from future Royalty income.

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.

Note 4—Federal Income Tax Matters

In a technical advice memorandum dated February 26, 1982, the National Office of 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. Accordingly, no income taxes are provided in the financial statements.

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, 2004. Any discussion of “actual” production volumes represents the hydrocarbons that were produced from the properties in which the Trust has an overriding royalty interest.

The Trust is a passive entity whose purposes are limited to: (1) converting the Royalties to cash, either by retaining them and collecting the proceeds of production (until production has ceased or the Royalties are otherwise terminated) or by selling or otherwise disposing of the Royalties; and (2) distributing such cash, net of amounts for payments of liabilities to the Trust, to the unitholders. The Trust has no sources of liquidity or capital resources other than the revenues, if any, attributable to the Royalties and interest on cash held by the Trustee as a reserve for liabilities or for distribution.

Note Regarding Forward-Looking Statements

This Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-Q, including without limitation the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” are forward-looking statements. Although the Working Interest Owners have advised the Trust that they believe that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove to 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 summary illustrates the net effect of the components of the actual Royalty computation for the periods indicated:

	Three Months Ended June 30,
	2005							2004
	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)	$	2,735,473			$	741,521		$	2,514,460			$	639,384
Less the Trust’s proportionate share of:
Capital costs recovered(2)	(246,397		)		—			(133,173		)		—
Operating costs	(777,741		)		(87,838		)	(757,815		)		(72,393		)
Interest on cost carryforward	—				—			(2,657		)		—
Withheld revenues(3)	(120,457		)		—			—				—
Royalty income	$	1,590,878			$	653,683		$	1,620,815			$	566,991
Average sales price	$	5.77			$	30.75		$	5.00			$	24.85
	(Mcf)				(Bbls)			(Mcf)				(Bbls)
Net production volumes attributable to the Royalty(4)	275,769				21,261			324,015				22,818

	Six Months Ended June 30,
	2005							2004
	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)	$	5,650,245			$	1,580,614		$	4,854,365			$	1,271,262
Less the Trust’s proportionate share of:
Capital costs recovered(2)	(450,030		)		—			(227,841		)		—
Operating costs	(1,535,529		)		(168,593		)	(1,397,356		)		(144,474		)
Interest on cost carryforward	—				—			(6,124		)		—
Withheld revenues(3)	(292,905		)		—			—				—
Royalty income	$	3,371,781			$	1,412,021		$	3,223,044			$	1,126,788
Average sales price	$	5.89			$	32.25		$	4.70			$	23.83
	(Mcf)				(Bbls)			(Mcf)				(Bbls)
Net production volumes attributable to the Royalty(4)	572,512				43,785			686,166				47,285

(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 $0 and $135,197 at June 30, 2005 and June 30, 2004, respectively. The cost carryforward at June 30, 2005 and June 30, 2004 relate solely to the San Juan Basin Colorado properties.

(3) The Colorado portion of the San Juan Basin Royalty properties has paid off the Fruitland Coal drilling program costs as of December 2004; however subsequent earnings now totaling $340,191 have not yet been remitted. Since Royalty income for the Trust is recorded on a cash basis, royalty income for the three and six months ended June 30, 2005 of $120,457 and $292,905, respectively, cannot be recognized.

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

Three Months Ended June 30, 2005 and 2004

	Three Months Ended June 30,
	2005			2004
Royalty income	$	2,244,561		$	2,187,806
Interest income	3,545			2,429
General and administrative expense	(19,608		)	(19,195		)
Distributable income	$	2,228,498		$	2,171,040
Distributable income per unit	$	1.1958		$	1.1650
Units outstanding	1,863,590			1,863,590

The Trust’s Royalty income was $2,244,561 in the second quarter 2005, an increase of approximately 3% as compared to $2,187,806 in the second quarter 2004, primarily as a result of higher natural gas and natural gas liquid prices in the second quarter of 2005 as compared to the second quarter of 2004, offset slightly by decreased production.

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, 2005 was $2,228,498, representing $1.1958 per unit, compared to $2,171,040, representing $1.1650 per unit, for the quarter ended June 30, 2004. Based on 1,863,590 units outstanding for the quarters ended June 30, 2005 and 2004, respectively, the per unit distributions were as follows:

	2005		2004
April	$	0.3886	$	0.4340
May	0.4181		0.3682
June	0.3891		0.3628
	$	1.1958	$	1.1650

Hugoton Field

Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 51% of the Royalty income of the Trust during the second quarter of 2005.

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 Tenaska, Greely Gas, Oneok Gas Marketing, Inc., and Anadarko Energy

Services, 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. Overall market prices received for natural gas from the Hugoton Royalty Properties were higher in the second quarter of 2005 compared to the second quarter of 2004.

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, 2001. PNR extended the contract to June 1, 2006. 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 decreased to $1,150,474 in the second quarter of 2005, as compared to $1,230,973 in the second quarter of 2004. The decrease in Royalty income was primarily due to declines in natural gas production. The average price received in the second quarter of 2005 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $6.02 per Mcf and $29.72 per barrel, respectively, compared to $5.44 per Mcf and $24.68 per barrel during the same period in 2004. Net production attributable to the Hugoton Royalty was 134,439 Mcf of natural gas and 11,479 barrels of natural gas liquids in the second quarter of 2005 compared to 169,856 Mcf of natural gas and 12,437 barrels of natural gas liquids in the second quarter of 2004. Actual production volumes attributable to the Hugoton properties decreased to 191,237 Mcf of natural gas and 11,478 barrels of natural gas liquids in the second quarter of 2005 as compared to 219,773 Mcf of natural gas and 12,426 barrels of natural gas liquids for the same period in 2004 as a result of natural production decline.

Capital expenditures on these properties were $73,150 in the second quarter of 2005, as compared to $1,295 in the second quarter of 2004 . Operating costs were $267,902 in the second quarter of 2005, a decrease of approximately 1% as compared to $270,400 in the second quarter of 2004.

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, 2005 through September 30, 2005, at 129.5 Bcf of gas, compared with 143.5 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. Substantially all of the Royalty income from the San Juan Basin Royalty Properties are located in the state of New Mexico. The Royalty income was $1,094,087 during the second quarter of 2005 as compared with $956,833 in the second quarter of 2004. The increase in Royalty income was due primarily to increased natural gas prices in the second quarter of 2005 as compared to the second quarter of 2004. The average price received in the second quarter of 2005 for natural gas sold from the San Juan Basin Royalty Properties was $5.53 per Mcf and $31.95 per barrel, respectively, compared to $4.52 per Mcf and $25.05 per barrel during the same period in 2004. Net production attributable to the San Juan Basin Royalty located in New Mexico was 141,330 Mcf of natural gas and 9,782 barrels of natural gas liquids in the second quarter of 2005 as compared to 154,159 Mcf of natural gas and 10,381 barrels of natural gas liquids in the second quarter of 2004. Actual production volumes attributable to the San Juan Basin

properties decreased to 259,320 Mcf of natural gas and 12,533 barrels of natural gas liquids in the second quarter of 2005 as compared to 262,498 Mcf of natural gas and 13,273 barrels of natural gas liquids for the same period in 2004 as a result of natural production decline.

Capital expenditures on these properties were $173,247 in the second quarter of 2005, an increase of approximately 130% as compared to $75,360 in the second quarter of 2004. Operating costs were $566,069 in the second quarter of 2005, an increase of approximately 16% as compared to $487,927 in the second quarter of 2004.

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 represented approximately 64% of the Trust’s estimated reserves as of December 31, 2004. 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 as of December 31, 2004.

The Colorado portion of the San Juan Basin Royalty properties recovered its costs of the Fruitland Coal drilling program costs as of December 2004; however, subsequent earnings now totaling $340,191 have not been remitted. Since Royalty income is recorded on a cash basis, Royalty income of $120,457 for the three months ended June 30, 2004 cannot be recognized.

Six Months Ended June 30, 2005 and 2004

	Six Months Ended June 30,
	2005			2004
Royalty income	$	4,783,802		$	4,349,832
Interest income	7,160			4,627
General and administrative expense	(39,612		)	(29,819		)
Distributable income	$	4,751,350		$	4,324,640
Distributable income per unit	$	2.5496		$	2.3206
Units outstanding	1,863,590			1,863,590

The Trust’s Royalty income was $4,783,802 ($2.5496 per unit) for the six months ended June 30, 2005, an increase of approximately 10% as compared to $4,349,832 ($2.3206 per unit) for the six months ended June 30, 2004, primarily as a result of higher natural gas and natural gas liquid prices in the first six months of 2005 as compared to the first six months of 2004, offset slightly by decreased production.

Hugoton Field

Royalty income attributable to the Hugoton Royalty Properties increased to $2,543,648 for the six months ended June 30, 2005 from $2,385,754 for the same period in 2004. The average price received in the first six months of 2005 for natural gas and natural gas liquids sold from the Hugoton field was $6.08 per Mcf and $32.42 per barrel, compared to $4.91 per Mcf and $23.26 per barrel during the same period in 2004. Net production attributable to the Hugoton Royalty Properties decreased to 292,794 Mcf of natural gas and 23,549 barrels of natural gas liquids for the six months ended June 30, 2005 as compared to 361,649 Mcf of natural gas and 26,228 barrels of natural gas liquids for the six months ended June 30, 2004. Actual

production volumes attributable to the Hugoton Royalty Properties decreased to 395,889 Mcf of natural gas and 23,549 barrels of natural gas liquids in the six months ended June 30, 2005 as compared to 462,268 Mcf of natural gas and 26,215 barrels of natural gas liquids for the same period in 2004 as a result of natural production decline.

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 are located in the state of New Mexico. The Royalty income was $2,240,154 for the first six months of 2005 compared to $1,964,078 in the first six months of 2004. The increase in Royalty income was due primarily to increased natural gas and natural gas liquid prices in the first six months of 2005 from the San Juan Basin properties. The average price received in the six months ended June 30, 2005 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties was $5.70 per Mcf and $32.06 per barrel, respectively, compared to $4.46 per Mcf and $24.54 per barrel during the same period in 2004. Net production attributable to the San Juan Basin Royalty located in New Mexico was 279,718 Mcf of natural gas and 20,236 barrels of natural gas liquids for the six months ended June 30, 2005 as compared to 324,517 Mcf of natural gas and 21,057 barrels of natural gas liquids for the six months ended June 30, 2004. Actual production volumes attributable to the San Juan Basin Royalty Properties decreased to 509,293 Mcf of natural gas and 25,494 barrels of natural gas liquids in the six months ended June 30, 2005 as compared to 530,566 Mcf of natural gas and 26,941 barrels of natural gas liquids for the same period in 2004 as a result of natural production decline.

The Colorado portion of the San Juan Basin Royalty properties has paid off the Fruitland Coal drilling program costs as of December 2004; however, subsequent earnings now totaling $340,191 have not been remitted. Since Royalty income is recorded on a cash basis, Royalty income of $292,905 for the six months ended June 30, 2004 cannot be recognized.

Item 3. Quantitative and Qualitative Disclosure About Market Risk.

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

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 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 end of the period covered by 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 these controls and procedures are effective.

Due to the contractual arrangements of (i) the Trust Indenture and (ii) the rights of the Trust under the Conveyance regarding information furnished by the working interest owners, the Trustee relies on (A) information provided by the working interest owners, including the status of litigation potentially affecting the Royalty Properties, historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, and (B) conclusions regarding reserves by reserve engineers or other experts. See Item I “Business—Principal Risk Factors—None of the Trustee, the Trust nor its unitholders control the operation or development of the Royalty Properties and have little influence over operation or development” in the Trust’s Form 10-K for the year ended December 31, 2004 for a description of certain risks relating to these arrangements and reliance.

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.

Item 5. Legal Proceedings.

entered a judgment or findings, it could do so at any time. PNR strongly denies the existence of any material underpayment to the plaintiffs and believes it presented strong evidence at trial to support its positions.

PART II—OTHER INFORMATION

Item 6. Exhibits

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

			SEC File or Registration Number	Exhibit Number
4(a)	*	Mesa Royalty Trust Indenture between Mesa Petroleum Co. andTexas 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

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, N.A. Trustee
		By:
				Mike Ulrich
				Vice President & Trust Officer

Date: August 9, 2005

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.