Mesa Offshore Trust (MOSH) 10-Q 2002 Q3 Quarterly report

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

/X/	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
/ /	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 1-8432

MESA OFFSHORE TRUST

(Exact name of Registrant as Specified in its Charter)

Texas	76-6004065
(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 /x/    No / /

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

        As of November 14, 2002—71,980,216 Units of Beneficial Interest in Mesa Offshore Trust.

PART I—FINANCIAL INFORMATION

Item 1.    Financial Statements.

MESA OFFSHORE TRUST

STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)

		Three Months Ended September 30,						Nine Months Ended September 30,
		2002			2001			2002			2001
Royalty income		$	—		$	346,443		$	—		$	$1,574,833
Interest income			5,329			23,244			18,154			82,486
General and administrative expense			(5,329	)		(128,233	)		(18,154	)		(398,157	)
	Distributable income	$	—		$	241,454		$	—		$	1,259,162
	Distributable income per unit	$	—		$	0.0034		$	—		$	0.0175

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

			September 30, 2002			December 31, 2001
			(Unaudited)
ASSETS
Cash and short-term investments			$	1,613,331		$	2,136,891
Interest receivable				5,329			5,052
Net overriding royalty interest in oil and gas properties				380,905,000			380,905,000
Accumulated amortization				(380,893,873	)		(380,893,873	)
		Total assets	$	1,629,787		$	2,153,070
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses			$	1,618,660		$	2,000,000
Distributions payable				—			141,943
Trust corpus (71,980,216 units of beneficial interest authorized and outstanding)				11,127			11,127
	Total liabilities and trust corpus		$	1,629,787		$	2,153,070

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

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MESA OFFSHORE TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS

(Unaudited)

		Three Months Ended September 30,					Nine Months Ended September 30,
		2002		2001			2002		2001
Trust corpus, beginning of period		$	11,127	$	20,703		$	11,127	$	23,556
	Distributable income		—		241,454			—		1,259,162
	Distributions to unitholders		—		(241,454	)		—		(1,259,162	)
	Amortization of net overriding royalty interest		—		(804	)		—		(3,657	)
Trust corpus, end of period		$	11,127	$	19,899		$	11,127	$	19,899

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

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MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1—Trust Organization

        The Mesa Offshore Trust (the "Trust") was created effective December 1, 1982. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership, which was the predecessor to MESA Inc., transferred to the Trust a 99.99% interest in the Mesa Offshore Royalty Partnership (the "Partnership"). The Partnership was created to receive and hold a net overriding royalty interest (the "Royalty") in ten producing and nonproducing oil and gas properties located in federal waters offshore Louisiana and Texas (the "Royalty Properties"). Mesa Inc. created the Royalty out of its working interest in the Royalty Properties and transferred it to the Partnership. Until August 7, 1997, MESA Inc. owned and operated its assets through Mesa Operating Co. ("Mesa"), the operator and the managing general partner of the Royalty Properties. 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) a wholly owned subsidiary of Pioneer ("PNR") (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, Pioneer owns and operates its assets through PNR and is also the managing general partner of the Partnership. As used in this report, the term PNR generally refers to the operator of the Royalty Properties, unless otherwise indicated.

Status of the Trust

        The Trust Indenture provides that the Trust will terminate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years (the "Termination Threshold"). The December 31, 2001 reserve report prepared for the Partnership (see the Trust's 2001 Annual Report on Form 10-K) indicates that Royalty income expected to be received by the Trust in 2002 and thereafter could be below the Termination Threshold. The year end 2001 reserve report estimated that future Royalty income to the Trust was approximately $1.6 million while the Termination Threshold for 2001 was approximately $1.3 million. Future Royalty income in the reserve report was calculated using oil and natural gas spot prices in effect at December 31, 2001 of $19.76 per barrel and $2.73 per Mcf, respectively. Based on available current information, the Trustee expects that Royalty income received by the Trust will be below the Termination Threshold in 2002. In addition, depending on the future price of oil and natural gas, the timing of production, market conditions, success of future drilling activity, if any, and other matters, the Royalty income received by the Trust after 2002 may be below the Termination Threshold. If Royalty income falls below the Termination Threshold for three successive years, the Trust would terminate pursuant to the terms of the Trust Indenture discussed above. There are numerous uncertainties inherent in estimating and projecting the quantity and value of proved reserves for the Trust properties as many of the Trust properties are nearing the end of their productive lives and are therefore subject to unforeseen changes in production rates. As such, there can be no assurance that Royalty income received by the Trust in 2002 or thereafter will be above the Termination Threshold.

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Note 2—Basis of Presentation

        The accompanying unaudited financial information has been prepared by JPMorgan Chase Bank (the "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 2001 Annual Report on Form 10-K.

        The financial statements of the Trust are prepared on the following basis:

        (a)  Royalty income recorded for a month is the Trust's interest in the amount computed and paid by the working interest owner to the Partnership for such month rather than either the value of a portion of the oil and gas produced by the working interest owner for such month or the amount subsequently determined to be 90% 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 interest, which is calculated on the basis of current royalty income in relation to estimated future royalty income, 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 considered 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 generally accepted in the United States. 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.

        The instruments conveying the Royalty provide that the working interest owner will calculate and pay the Partnership each month an amount equal to 90% of the net proceeds for the preceding month.

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Generally, net proceeds means the excess of the amounts received by the working interest owner from sales of oil and gas from the Royalty Properties plus other cash receipts over operating and capital costs incurred. For the three and nine months ending September 30, 2002, operating and capital costs incurred exceeded proceeds from oil and gas sales; accordingly, no Royalty income was reported. There is a deficit balance due PNR as of September 30, 2002 of $399,843 that will be deducted from any future gross proceeds on the Royalty Properties, which deduction will reduce future Royalty income. In addition, no Royalty income will be distributed to unitholders until the Trustee recoups Trust expenses being paid from the reserve that the Trustee has established for anticipated future expenses. As of September 30, 2002, $381,340 will be recouped by the Trustee from future Royalty income before Trust distributions will resume. The unexpended amount withheld by PNR for future abandonment costs at September 30, 2002 was $7,793,293.

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

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" and Note 1 to the financial statements of the Trust regarding the future net revenues of the Trust, are forward-looking statements. Although Pioneer has advised the Trust that it believes that the expectations reflected in such 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, including without limitation in conjunction with the forward-looking statements included in this Form 10-Q and in the Trust's Form 10-K. 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.

Financial Review

        During the third quarter of 2002, the Trust had no distributable income, compared to $241,454, or $.0034 per unit, in the third quarter of 2001. The decrease in distributable income in 2002 was primarily due to lower production at West Delta 61 and 62 and Matagorda Island 624 as described in the "Operational Review" below and the fact that the Trust is currently in a deficit position of $399,843. The per unit distributions for the third quarter of 2002 and 2001 were as follows:

	2002		2001
July	$	—		—
August		—		.0026
September		—		.0008
	$	—	$	.0034

        There was no Royalty income in the third quarter of 2002 as compared to $346,443 in the third quarter of 2001. The decrease in Royalty income is primarily due to substantially lower production volumes on West Delta 61 and 62 and Matagorda Island 624 and decreased prices for natural gas, crude oil and condensate as compared to the same period in 2001.

        There is a deficit balance due PNR as of September 30, 2002 of $399,843 that will be deducted from any future gross proceeds on the Royalty Properties, which deduction will reduce future Royalty income. In addition, there will be no income distributed to unitholders until the Trustee recoups Trust expenses being paid from the reserve that the Trustee established. As of September 30, 2002, $381,340 will be recouped by the Trustee from future Royalty income before Trust distributions to unitholders will resume. The unexpended amount withheld by PNR for future abandonment costs at September 30, 2002 was $7,793,293.

        Production volumes for natural gas decreased to 59,918 Mcf in the third quarter of 2002 from 120,922 Mcf in the third quarter of 2001. The decrease is primarily due to decreased production at West

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Delta 61 and 62 and Matagorda Island 624. The average price received for natural gas was $3.20 per Mcf in the third quarter of 2002 as compared to $4.44 per Mcf in the third quarter of 2001.

        Crude oil, condensate and natural gas liquids production decreased to 124 barrels in the third quarter of 2002 from 2,979 barrels in the third quarter of 2001. The average price received for crude oil, condensate and natural gas liquids was $22.14 per barrel in the third quarter of 2002, compared to $26.50 per barrel in the third quarter of 2001.

        For the nine months ended September 30, 2002, natural gas production volumes decreased to 263,912 Mcf from 367,275 Mcf for the nine months ended September 30, 2001. The average price received for natural gas was $2.42 per Mcf for the nine months ended September 30, 2002 compared to $5.38 per Mcf for the nine months ended September 30, 2001. Crude oil, condensate and natural gas liquid volumes decreased to 4,813 barrels in the first nine months of 2002 as compared to 14,722 barrels in the first nine months of 2001. The average price received for crude oil, condensate and natural gas liquids was $21.12 per barrel for the nine months ended September 30, 2002 compared to $26.22 per barrel for the nine months ended September 30, 2001.

        The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of natural gas, crude oil, condensate and natural gas liquids produced from the Royalty Properties and the quantities sold. Substantial uncertainties exist with regard to future natural gas and oil prices, which are subject to fluctuations due to the regional supply and demand for natural gas and oil, production levels and other activities of the Organization of the Petroleum Exporting Countries ("OPEC") and other oil and gas producers, weather, storage levels, industrial growth, conservation measures, competition and other variables.

Operational Review

        PNR has advised the Trust that during the third quarter of 2002 its offshore gas production was marketed under short-term contracts at spot market prices primarily to H&N, Limited and that it expects to continue to market its production under short-term contracts for the foreseeable future. Spot market prices for natural gas in the third quarter of 2002 were generally lower than spot market prices in the third quarter of 2001.

        The Brazos A-7 and A-39 blocks experienced a decrease in natural gas production in the third quarter of 2002 as compared to the third quarter of 2001 primarily due to natural production decline. As of September 30, 2002, these two blocks had two wells producing, the Brazos A-7 No. B-1 well and the Brazos A-39 No. A-3 well. The Brazos A-7 No. A-4 well, operated by PNR, ceased production in late 2001, came back on production during the first quarter of 2002 after a successful workover and ceased production in the third quarter after loading up with water. The Brazos A-39 No. A-3 well, operated by PNR, ceased production in May 31, 2001 and was returned to production November 12, 2001 after successfully unloading the well. The No. A-3 well continues to produce intermittently. PNR is evaluating the Brazos A-39 wells for any additional recompletions that could be performed. The Brazos A-7 No. B-1 well, operated by Newfield Exploration Company, is currently the only remaining consistently producing well on these blocks. PNR farmed out their interest and the Trust's interest in one-fourth of the Brazos A-39 block to Shell Oil Company in late 2000 in return for a 2% (1.8% net to the Trust) override in the one-fourth of the Brazos A-39 block farmed out and one-fourth of the three surrounding blocks. In addition, PNR has informed the Trustee that it is attempting to farm out the Trust's share of portions of these two blocks so that two prospects can potentially be drilled sometime in 2003. However, there can be no assurance that any of these three prospects on these two blocks will ever be drilled.

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        The Matagorda Island 624 block, operated by PNR, experienced a production decrease in the third quarter of 2002 as compared to the third quarter of 2001 because the only remaining producing well, MI 624 No. A-1, ceased production in the first quarter of 2002. PNR attempted a workover on the well early in the second quarter of 2002, but discontinued the workover due to mechanical problems. During the third quarter of 2002, PNR attempted to repair the wellbore and complete the workover but was unsuccessful. No other prospects are identified and therefore PNR held a partner meeting to discuss abandoning the property. All partners have tentatively approved such operations pending Mineral Management Service approval and cost estimates.

        The West Delta 61 and 62 blocks experienced a decrease in oil and natural gas production in the third quarter of 2002 as compared to the second quarter of 2001 due to natural production declines in one well and the other two wells being shut-in. PNR has studied these leases and attempted to sell the platform and other facilities without success. PNR had no prospects identified and therefore initiated plugging and abandonment procedures during the second quarter of 2002 on the PNR operated wells and platform that should be completed by the end of this year. In West Delta 62, the Trust was receiving Royalty income from one producing well pursuant to a farmout agreement with Walter Oil and Gas Corporation ("Walter"). However, the well ceased production during the first quarter of 2002 and Walter has commenced plugging and abandonment procedures for that well. In West Delta 61, PNR farmed out portions of the block to Stone Energy Corporation ("Stone"), retaining a 12.5% (11.25% net to the Trust) overriding Royalty interest. Since the first quarter of 2002, Stone has shut-in their two wells because the host platform, which is operated by another company, was converted from a manned platform to an unmanned platform. Stone has subsequently negotiated with Walter to reroute their wells to the Walter platform in West Delta block 62. This work has commenced and the wells should be placed back on production during the fourth quarter of 2002.

        The South Marsh Island 155 and 156 blocks ceased production during the first quarter of 2000. The lease was relinquished and abandonment procedures were commenced during the second quarter of 2001. The abandonment of the last platform and the site clearance operation will both be completed by the end of 2002.

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        The following tables provide a summary of the calculations of the net proceeds attributable to the Partnership's Royalty interest (unaudited):

			Brazos A-7 and A-39			Matagorda Island 624			West Delta 61 and 62			South Marsh Island 155 and 156			Total
Three Months Ended September 30, 2002:
	Ninety percent of gross proceeds		$	155,710		$	37,977		$	932		$	—		$	194,619
	Less ninety percent of—
		Operating expenditures		(79,256	)		(38,624	)		(63,330	)		(6,117	)		(187,327	)
		Capital costs recovered		—			(7,292	)		—			—			(7,292	)
		Accrual for future abandonment costs and interest on cost carryforward		—			—			—			—			—
	Net proceeds (excess costs)		$	76,454		$	(7,939	)	$	(62,398	)	$	(6,117	)	$	—
	Trust share of net proceeds (99.99%)														$	—
	Production Volumes and Average Prices:
		Crude oil, condensate and natural gas liquids (Bbls)		68			24			32			—			124
		Average sales price per Bbl	$	21.92		$	25.79		$	19.86		$	—		$	22.14
		Natural gas (Mcf)		49,646			10,184			88			—			59,918
		Average sales price per Mcf	$	3.11		$	3.67		$	3.30		$	—		$	3.20
	Producing wells			2			—			—			—			2
			Brazos A-7 and A-39			Matagorda Island 624			West Delta 61 and 62			South Marsh Island 155 and 156			Total
Three Months Ended September 30, 2001:
	Ninety percent of gross proceeds		$	188,490		$	229,187		$	198,720		$	(977	)	$	615,420
	Less ninety percent of—
		Operating expenditures		(93,153	)		(74,310	)		(72,074	)		(26,102	)		(265,639	)
		Capital costs recovered		—			(3,303	)		—			—			(3,303	)
		Accrual for future abandonment costs and interest on cost carryforward		—			—			—			—			—
	Net proceeds		$	95,337		$	151,574		$	126,646		$	(27,079	)	$	346,478
	Trust share of net proceeds (99.99%)														$	346,443
	Production Volumes and Average Prices:
		Crude oil, condensate and natural gas liquids (Bbls)		13			292			2,674			—			2,979
		Average sales price per Bbl	$	24.85		$	28.40		$	26.30		$	—		$	26.50
		Natural gas (Mcf)		42,786			49,866			28,270			—			120,922
		Average sales price per Mcf	$	4.40		$	4.43		$	4.56		$	—		$	4.44
		Producing wells		1			1			3			—			5

•

The amounts shown are for Mesa Offshore Royalty Partnership.

•

The amounts for the three months ended September 30, 2002 and 2001 represent actual production for the periods May 2002 through July 2002 and May 2001 through July 2001, respectively.

•

Capital costs recovered represents capital costs incurred during the current or prior periods to the extent that such costs have been recovered by PNR from current period Gross Proceeds.

•

Producing wells indicate the number of wells capable of production as of the end of the period.

•

The cost carryforward related to operating and capital costs incurred exceeding oil and gas sales at September 30, 2002 was $399,843.

•

The unexpended amount withheld by PNR for future abandonment costs at September 30, 2002 was $7,793,293.

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			Brazos A-7 and A-39			Matagorda Island 624			West Delta 61 and 62			South Marsh Island 155 and 156			Total
Nine Months Ended September 30, 2002:
Ninety percent of gross proceeds			$	404,864		$	189,045		$	146,460		$	—		$	740,369
	Less ninety percent of—
		Operating expenditures		(401,563	)		(94,617	)		(181,165	)		(53,714	)		(731,059	)
		Capital costs recovered		—			(9,310	)		—			—			(9,310	)
		Accrual for future abandonment costs		—			—			—			—			—
	Net proceeds (excess costs)		$	3,301		$	85,118		$	(34,705	)	$	(53,714	)	$	—
	Trust share of net proceeds (99.99%)														$	—
	Production Volumes and Average Prices:
		Crude oil, condensate and natural gas liquids (Bbls)		398			851			3,564			—			4,813
		Average sales price per Bbl	$	19.52		$	20.45		$	21.46		$	—		$	21.12
		Natural gas (Mcf)		167,605			71,387			24,920			—			263,912
		Average sales price per Mcf	$	2.37		$	2.40		$	2.81		$	—		$	2.42
	Producing wells			2			—			—			—			2
			Brazos A-7 and A-39			Matagorda Island 624			West Delta 61 and 62			South Marsh Island 155 and 156			Total
Nine Months Ended September 30, 2001:
	Ninety percent of gross proceeds		$	1,178,708		$	279,101		$	906,154		$	(727	)	$	2,363,236
	Less ninety percent of—
		Operating expenditures		(250,759	)		(146,127	)		(198,207	)		(114,198	)		(709,291	)
		Capital costs recovered		(48,703	)		(18,127	)		—			(2,124	)		(68,954	)
		Accrual for future abandonment costs		(6,106	)		(72	)		(3,822	)		—			(10,000	)
	Net proceeds		$	873,140		$	114,775		$	704,125		$	(117,049	)	$	1,574,991
	Trust share of net proceeds (99.99%)														$	1,574,833
	Production Volumes and Average Prices:
		Crude oil, condensate and natural gas liquids (Bbls)		234			708			13,780			—			14,722
		Average sales price per Bbl	$	27.09		$	25.04		$	12.93		$	—		$	26.22
		Natural gas (Mcf)		215,938			56,185			95,063			89			367,275
		Average sales price per Mcf	$	5.43		$	4.65		$	5.72		$	—		$	5.38
	Producing wells			1			1			3			—			5

•

The amounts shown are for Mesa Offshore Royalty Partnership.


•

The amounts for the nine months ended September 30, 2002 and 2001 represent actual production for the periods November 2001 through July 2002, and November 2000 through July 2001, respectively.


•

Capital costs recovered represents capital costs incurred during the current or prior periods to the extent that such costs have been recovered by PNR from current period Gross Proceeds.


•

Producing wells indicate the number of wells capable of production as of the end of the period.


•

The cost carryforward related to operating and capital costs incurred exceeding oil and gas sales at September 30, 2002 was $399,843.


•

The unexpended amount withheld by PNR for future abandonment costs at September 30, 2002 was $7,793,293.

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Termination of the Trust

        The terms of the Mesa Offshore Trust Indenture provide, among other things, that the Trust will terminate upon the first to occur of the following events: (1) the total amount of cash received per year by the Trust for each of three successive years, commencing after December 31, 1987, is less than ten times one-third of the total amount payable to the Trustee as compensation for such three-year period ("the Termination Threshold") or (2) a vote by holders of a majority of the outstanding units in favor of termination. Because the Trust will terminate in the event the total amount of cash received per year by the Trust falls below certain levels, it would be possible for the Trust to terminate even though some of the Royalty Properties continued to have remaining productive lives. For information regarding the estimated remaining life of each of the Royalty Properties and the estimated future net revenues of the Trust based on information provided by PNR, see the Trust's 2001 Annual Report on Form 10-K. 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. The discussion set forth above is qualified in its entirety by reference to the Trust Indenture itself, which is an exhibit to the Trust's 2001 Annual Report on Form 10-K and is available upon request from the Trustee.

        The December 31, 2000 reserve report prepared for the Partnership indicates that Royalty income expected to be received by the Trust in 2002 and thereafter could be below the Termination Threshold. The year end reserve report estimates that future Royalty income to the Trust was approximately $1.6 million, while the Termination Threshold for 2001 was approximately $1.3 million. Future Royalty income in the reserve report was calculated using oil and natural gas spot prices in effect at December 31, 2000 of $19.76 per barrel and $2.73 per Mcf, respectively. Based on available current information, the Trustee expects that Royalty income received by the Trust will be below the Termination Threshold in 2002. In addition, depending on the future price of oil and natural gas, the timing of production, market conditions, success of future drilling activity, if any, and other matters, the Royalty income received by the Trust after 2002 may be below the Termination Threshold. If Royalty income falls below the Termination Threshold for three successive years, the Trust would terminate pursuant to the terms of the Trust Indenture discussed above. There are numerous uncertainties inherent in estimating and projecting the quantity and value of proved reserves for the Trust properties as many of the Trust properties are nearing the end of their productive lives and are therefore subject to unforeseen changes in production rates. As such, there can be no assurance that Royalty income received by the Trust in 2002 or thereafter will be above the Termination Threshold.

        The terms of the First Amended and Restated Articles of General Partnership of the Partnership provide that the Partnership shall dissolve upon the occurrence of any of the following: (a) December 31, 2030; (b) the election of the Trustee to dissolve the Partnership; (c) the termination of the Trust; (d) the bankruptcy of the Managing General Partner; or (e) the dissolution of the Managing General Partner or its election to dissolve the Partnership; provided that the Managing General Partner shall not elect to dissolve the Partnership so long as the Trustee remains the only other partner of the Partnership. In the event of a dissolution of the Partnership and a subsequent winding up and termination thereof, the assets of the Partnership (i.e., the Royalty interest) could either (i) be distributed in kind ratably to the Managing General Partner and the Trustee or (ii) be sold and the proceeds thereof distributed ratably to the Managing General Partner and the Trustee. In the event of a sale of the Royalty and a distribution of the cash proceeds to the Trustee, the Trustee would make a final distribution to unitholders of such cash proceeds plus any other cash held by the Trust after the payment of or provision for all liabilities of the Trust, and the Trust would be terminated.

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Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

        The Trust does not utilize market risk sensitive instruments. However, see the discussion of marketing by PNR 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 Pioneer, as the managing general partner of the Partnership, and the working interest owners to JPMorgan Chase Bank, 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.

        Within 90 days 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, (ii) the Partnership Agreement and (iii) the rights of the Partnership 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 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.


•

The Trustee relies on information provided by the managing general partner of the Partnership that is collected by the managing general partner from the working interest owners. While the Trustee may request information through the managing general partner, the Conveyance together with the Partnership Agreement gives only the managing general partner of the Partnership, as the Royalty Owner, the actual authority and discretion to request and receive financial information regarding the Royalty Properties from the working interest owners. While the Trustee requests material information for use in periodic reports as part of its disclosure controls and procedures, the Trustee generally does not have any direct contact with working interest owners, other than employees of the managing general partner, and relies on the managing general partner of the Partnership to request and obtain information deemed material to the Trust by the Trustee.

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•

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 managing general partner and the working interest owners. Other than contracting independent auditors and reviewing the managing general partner's statements on a quarterly basis, 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 or the managing general partner of the Partnership.

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PART II

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 is the 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 Offshore Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982	2-79673	10	(gg)
4	(b)	*Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty Partnership, dated December 15, 1982	2-79673	10	(hh)
4	(c)	*Partnership Agreement between Mesa Offshore Management Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982	2-79673	10	(ii)
4	(d)	*Amendment to Partnership Agreement between Mesa Offshore Management Co., Texas Commerce Bank National Association, as Trustee, and Mesa Operating Limited Partnership, dated December 27, 1985 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of Mesa Offshore Trust)	1-8432	4	(d)
4	(e)	*Amendment to Partnership Agreement between Texas Commerce Bank National Association, as Trustee and Mesa Operating dated as of January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December 31, 1993 of Mesa Offshore Trust)	1-8432	4	(e)

(b)

Reports on Form 8-K

        A current report on Form 8-K dated July 3, 2002 and filed on July 11, 2002, as amended, reported that the Trust dismissed Arthur Andersen LLP as its independent public accountants and engaged KPMG LLP to serve as its independent public accountants for 2002.

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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 OFFSHORE TRUST
By:	JPMORGAN CHASE BANK, TRUSTEE
By:	/s/  MIKE ULRICH      Mike Ulrich Vice President & Trust Officer

Date: November 14, 2002

        The Registrant, Mesa Offshore 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.

CERTIFICATION

        I, Mike Ulrich, certify that:

        1.    I have reviewed this quarterly report on Form 10-Q of Mesa Offshore 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-14 and 15d-14), or for causing such procedures to be established and maintained, for the registrant and have:

        a)    designed such disclosure controls and procedures, or caused such controls and procedures to be designed, 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 as of a date within 90 days prior to the filing date of this quarterly report (the 'Evaluation Date'); and

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        c)    presented in this quarterly report my conclusions about the effectiveness of the disclosure controls and procedures based on my evaluation as of the Evaluation Date;

        5.    I have disclosed, based on my most recent evaluation, to the registrant's auditors:

        a)    all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

        b)    any fraud, whether or not material, that involves any persons who have a significant role in the registrant's internal controls; and

        6.    I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of my most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

        In giving the foregoing certifications in paragraphs 4, 5 and 6, I have relied to the extent I consider reasonable on information provided to me by the working interest owners and the managing general partner of the Mesa Offshore Trust Partnership, in which the registrant owns a 99.99% interest.

Date: November 14, 2002
/s/  MIKE ULRICH      Mike Ulrich,
Vice President and Trust Officer
JPMorgan Chase Bank

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QuickLinks

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

MESA OFFSHORE TRUST STATEMENTS OF DISTRIBUTABLE INCOME (Unaudited)
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
MESA OFFSHORE TRUST STATEMENTS OF CHANGES IN TRUST CORPUS (Unaudited)
MESA OFFSHORE TRUST NOTES TO FINANCIAL STATEMENTS (Unaudited)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Item 4. Controls and Procedures.

PART II

Item 6. Exhibits and Reports on Form 8-K.

SIGNATURES
CERTIFICATION