Mesa Offshore Trust (MOSH) 10-Q 2005 Q1 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2005

oTRANSITION 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, 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 check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o  No x

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

As of May 20, 2005—71,980,216 Units of Beneficial Interest were outstanding in Mesa Offshore Trust.

PART I—FINANCIAL INFORMATION

Item 1.Financial Statements.

MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)

	Three Months Ended March 31,
	2005				2004
Royalty income		$	173,460			$	—
Interest income		796				1,638
General and administrative		(174,256		)		(1,638		)
Distributable income		$	—			$	—
Distributable income per unit		$	—			$	—

STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS

	March 31,         2005				December 31,     2004
	(Unaudited)
ASSETS
Cash and short-term investments		$	405,646			$	376,599
Interest receivable		295				250
Net overriding royalty interest in oil and gas properties		380,905,000				380,905,000
Accumulated amortization		(380,895,381		)		(380,893,873		)
Total assets		$	415,560			$	387,976
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses		$	405,941			$	376,849
Distributions payable		—				—
Trust corpus (71,980,216 units of beneficial interest authorized and outstanding)		9,619				11,127
Total liabilities and trust corpus		$	415,560			$	387,976

STATEMENTS OF CHANGES IN TRUST CORPUS

	Three Months Ended March 31,
	2005			2004
Trust corpus, beginning of period	$	11,127		$	11,127
Distributable income	—			—
Distributions to unitholders	—			—
Amortization of net overriding royalty interest	(1,508		)	—
Trust corpus, end of period	$	9,619		$	11,127

(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 hereinafter used in this report, the term PNR generally refers to the operator of the Royalty Properties, unless otherwise indicated.

Note 2—Status of the Trust, Legal Proceedings, and Timing of Liquidation

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”). As a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture, resulting in the contractual termination of the Trust effective after December 31, 2004. During 2005 the Trustee has taken steps to begin the process of liquidating the Trust. See below for Timing of Liquidation. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no discretion regarding the occurrence of the Termination Threshold or its consequences.

The Trust Indenture provides the Trustee a two-year period during which it must sell all of the Trust properties. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee expects that the sale process will be open to any persons desiring to participate, but, as is customary, access to information and participation may be limited to persons who execute confidentiality agreements regarding information provided by the working interest owners. The Trustee may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a “public” auction in the sense that it may not be open to anyone who does not satisfy these requirements. The Trustee is currently reviewing a potential online bidding process for participants in order to provide current public information on bidding to the marketplace. The Trustee will also determine a duration of bidding that it deems in the best interest of the unitholders.

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Legal Proceedings

On April 11, 2005, MOSH Holding, L.P. (MHLP) filed an Original Petition in the District Court of Travis County, Texas, 250th Judicial District, against Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc.; Woodside Energy (USA), Inc.(Woodside); and JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (Case No. GN501113). The Trustee is named as only a nominal defendant in this petition. In this petition, MHLP asserts claims for damages against Pioneer and Woodside for matters including (1) a wrongful farmout of Brazos A-39 by Pioneer to an alleged affiliate, (2) a wrongful delay by Pioneer in producing Brazos A-39, (3) fraudulent accounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aiding and abetting breach of fiduciary duty by Woodside, (6) misapplication of Trust property by Pioneer, (7) conspiracy to misapply fiduciary property by Woodside and Pioneer, (8) common law fraud by Pioneer, (9) gross negligence by Pioneer, and (10) breach of the conveyance agreement by Pioneer. The plaintiff remedies being sought include (a) reconstruing the Trust Indenture to determine that the Trust is not terminated because there has or should have been production which would have generated revenues to extend the life of the Trust, (b) requiring the Trustee to pursue certain claims, or to allow plaintiff to pursue such claims, (c) setting aside any farmouts by Pioneer in which there have been conveyances to an affiliate of Pioneer in violation of the Trust’s Conveyance and as a self-dealing transaction, and (d) monetary damages against Pioneer and Woodside.

Since the filing of the original petition, the Trustee has met with MHLP to ascertain the factual basis for its claims, and with both Pioneer and MHLP in connection with preliminary discovery. A review of information by the Trustee and MHLP remains in progress. The Trustee has also engaged DeGolyer & MacNaughton (D&M), an independent reserve engineer, to review the Brazos A-39 reserves and the Trust’s interest in these reserves. The Trustee expects that this reserve report will be made available for use in connection with the sale of the Trust properties as part of the Trust termination, as well as the pending litigation.

Timing of Liquidation

In connection with this litigation, the Trustee has agreed that it will give MHLP at least 60 days notice prior to the sale of any Trust properties in connection with the termination of the Trust. As of the date of this filing, based on the information currently provided by Pioneer and the preliminary state of the proceeding, the Trustee is unable to draw any conclusions as to the validity of the claims asserted by MHLP. However, the Trustee will continue the joint venture audit of the Trust properties by an independent auditor that had already begun its inquiry in the ordinary course as part of the termination of the Trust, and the Trustee is currently investigating MHLP’s claims.

As discussed above, the Trustee engaged an independent joint venture auditor during October 2004 to review the periods from 2003 through 2004. The Trustee believed this engagement of an outside expert on these matters to be a prudent step to identify any potential benefits to the Trust, as well as any limitations on potential benefits, due to differing interpretations of accounting matters or accounting errors that commonly occur in the oil and gas production industry. This audit remains ongoing and is currently expected to be completed in the latter half of 2005.

After sale of all of the Trust’s net overriding royalty interests in oil and gas properties and settlement of its liabilities, the Trust’s assets will consist solely of cash, which it will distribute to its unitholders.

Note 3—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

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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 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 because, under such 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. 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 months ended March 31, 2005, royalty income in excess of general and administrative expenses was applied solely to the Reserve for Trust Expenses; accordingly, no Trust distribution to the unit holders was made.

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. As of December 31, 2004, there was an accumulated deficit balance due PNR of $59,035. During January 2005 the accumulated deficit balance due the working interest owner was recouped and Royalty income was paid to the Trust during the first quarter of 2005. 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 March 31, 2005, $1,594,059 will be withheld by the Trustee from future Royalty income before Trust distributions to the unitholders will resume. The unexpended amount withheld by PNR for future abandonment costs at March 31, 2005 was $2,123,108.

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Note 4—Assets and Liabilities in process of liquidation

As a result of the contractual termination of the Trust effective January 1, 2005, the Trust is in the process of liquidation. The below table presents the assets and liabilities of the Trust at their estimated fair value:

	March 31,
	2005
ASSETS
Cash and short term investments	$	405,646
Interest receivable	295
Net overriding royalty interest in oil and gas properties	1,900,750
Total assets	$	2,306,691
LIABILITIES
Reserve for Trust expenses	$	405,941
Total liabilities	405,941
Net assets in process of liquidation	$	1,900,750

The net overriding royalty interest in oil and gas properties at March 31, 2005 reflect the Trustee’s estimate of value, (in the absence of third-party appraisals or evaluations) based on the Trust’s share of future net revenues from the net overriding royalty interest in the properties as of March 31, 2005. This estimate is based on the Trustee’s current assessment of the impact of selling existing assets based on current market conditions, and includes the following assumptions:

·The Trust’s estimated share of oil and gas reserve volumes at March 31, 2005, which were derived from the December 31, 2004 reserve report prepared by the working interest owner and updated for first quarter actual production. The working interest owner has not prepared a reserve report as of March 31, 2005, and therefore any revisions in oil and gas reserves during the first quarter 2005 have not been considered in the estimate of fair value of the net overriding royalty interest in oil and gas properties. The Trust’s estimated share of oil and gas reserve volumes at March 31, 2005 excluded reserves related to the Midway Prospect.(1)

·Forward strip commodity prices on March 31, 2005 for the life of the reserves

·Exclusion of estimated future abandonment costs(2)

·Discount rate of 10%

(1)As a result of the litigation described above, the Trust has been unable to obtain necessary information from the working interest owner in order to estimate the fair value of the proved reserves on  the Midway Prospect. The Trustee has engaged DeGolyer & MacNaughton (D&M), an independent reserve engineer, to review all oil and gas reserves pertaining to the Royalty, including the Brazos A-39 reserves and the Trust’s interest in these reserves.

(2)The sale of the assets currently owned by the Partnership will include the related rights to abandonment costs previously withheld by the working interest owner. The working interest owner has withheld funds to cover the Trust’s share of future abandonment and removal costs. To the extent the abandonment is completed for an amount less than the funds withheld by the working interest owner, those funds would be distributed to the Trust. Therefore, estimated future abandonment costs are not reflected as a reduction of future net revenue.

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The actual net proceeds from the sales of oil and gas properties may vary substantially from these estimates in value due to changes in current and estimated future oil and gas prices, subsequent production, estimates of actual abandonment costs and other factors which may be applied by the buyers.

For all other assets and liabilities presented in the above table, the Trustee believes that historical cost approximates fair market value due to the short-term nature of such assets and liabilities..

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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.

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 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 for the year ended 2004, 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.

Financial Review

The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of gas, crude oil, condensate and natural gas liquids produced from the Royalty Properties and the quantities sold. Substantial uncertainties exist with regard to future 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.

Below is a summary of Royalty income received on the Trust properties for the three months ended March 31, 2005 and 2004:

	Three Months Ended March 31,
	2005			2004
Gross proceeds @ 90%	$	272,298		$	240,941
Operating expenditures @ 90%	(39,780		)	(88,222		)
Capital expenditures @ 90%	—			—
Net proceeds (deficit)	232,518			152,719
Increase (decrease) in deficit	(59,041		)	(152,719		)
Net proceeds after deficit recovery	173,477			—
Royalty Income (99.99%)	$	173,460		$	—

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Below is a summary of distributable income for the three months ended March 31, 2005 and 2004:

	Three Months Ended March 31,
	2005			2004
Royalty Income	$	173,460		$	—
Interest income	796			1,638
General and administrative expenses	(174,256		)	(1,638		)
Distributable income	$	—		$	—
Distributable income per unit	$	—		$	—
Accumulated deficit (as of end of period)	$	—		$	(544,008	)

During the first quarters of 2005 and 2004, the Trust had no distributable income. Although the Trust repaid the accumulated deficit balance of $59,035 owed PNR, the Royalty income of $173,460 was used first to pay the Trust’s first quarter 2005 general and administrative expenses of $145,164, and the remaining Royalty income of $29,092 was applied to the Reserve for Trust expenses. As a result, the Trust there was no distributable income in the first quarter 2005.

Operational Review

PNR has advised the Trust that during the first quarter of 2005 its offshore gas production was marketed under short-term contracts at spot market prices primarily to Occidental Petroleum Corp. and TOTAL S.A. 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 first quarter of 2005 were generally higher than spot market prices in the first quarter of 2004.

The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of gas, crude oil and condensate produced from the Royalty Properties and the quantities sold. Substantial uncertainties exist with regard to future 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.

Below is an operational review of the remaining producing Trust properties:

Brazos A-7 and A-39

	Three Months Ended March 31,
	2005			2004
Gross proceeds @ 90%	$	36,081		$	90,524
Operating expenditures @ 90%	(28,439		)	(89,600		)
Capital expenditures @ 90%	—			—
Net proceeds (deficit)	$	7,642		$	924

The Brazos A-7 and A-39 blocks continued to experience a decrease in natural gas production due to natural production decline. As of March 31, 2005, these two blocks had one well producing, the Brazos A-7 No. B-1 well. The Brazos A-39 No. A-3 well ceased production during the fourth quarter of 2003. PNR entered into farmout agreements for the Trust’s interest in both of these blocks so that two exploration prospects could be drilled and in which the Trust will retain an overriding royalty interest. The first prospect on Brazos A-7 was drilled during 2003 and was determined to be a dry hole. As such, the well was plugged and abandoned.

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The second exploration prospect was drilled on Brazos A-39, which PNR has announced as a discovery. A production test was completed during the first quarter of 2005. PNR, the operator on this property, has informed the Trustee that the lower horizon of the prospect was determined to be non-commercial, while the middle horizon produced at 10 million cubic feet of gas per day during a seventeen hour flow test. There is no assurance that these flow rates will continue, as offshore oil and gas properties often experience stronger initial flow rates and more rapid declines than onshore properties. PNR expects to tie-back this prospect into an existing platform, operated by a third party, with first production expected to commence by the fourth quarter of 2005. Under the terms of a Farmout Agreement between PNR and Woodside Energy (USA) Inc., PNR farmed out to Woodside the undivided one-half interest previously burdened by the Trust’s net profits interest, but expressly providing that the farmed out interest would not be subject to the Trust’s net profits interest.  PNR reserved a 10% overriding royalty interest, proportionately reduced to the interest conveyed, which interest, upon Woodside’s recoupment of specified costs and expenses, would increase to 12.5%, proportionately reduced to the interest conveyed.  The Trust’s net profits interest burdens the overriding royalty interest reserved by PNR.  This process is consistent with the terms of the original conveyance and with the handling of other farmout transactions involving lands burdened by the Trust’s net profits interest.

PNR continues to own the undivided one-half interest not burdened by the Trust’s net profits interest and will participate in and operate the well as owner of that undivided one-half interest (subject to an agreement with Woodside to grant Woodside such interest in PNR’s remaining undivided one-half interest to equalize those parties participation in the well).

PNR has noted to the Trustee that the Farmout Agreement enabled the drilling costs of these prospects to be carried on the Trust’s interest in part by Woodside. PNR further noted that the Trust’s net profits interest would not have entitled the Trust to payment until drilling costs and applicable interest were recovered, whereas the overriding royalty interest retained under the Farmout Agreement entitles the Trust to payments prior to the recoupment of expenses incurred by Woodside and PNR. As noted above, the first prospect on Brazos A-7 was determined to be a dry hole. Under the Farmout Agreement and related agreements, those drilling and abandonment costs have been born entirely by PNR and Woodside and are not subject to recoupment from any proceeds otherwise payable to the Trust. Similarly, the Trust’s current interest in the “Midway” well on Brazos A-39 will be entitled to payment prior to PNR’s and Woodside’s recovery of expenses for drilling, completion, sub-sea tie backs and other costs.

The Brazos A-7 and A-39 blocks also experienced a significant decrease in operating expenditures due to the Brazos A-39 No. A-3 well no longer producing.

West Delta 61 and 62

	Three Months Ended March 31,
	2005			2004
Gross proceeds @ 90%	$	236,217		$	150,417
Operating expenditures @ 90%	(11,341		)	1,378
Capital expenditures @ 90%	—			—
Net proceeds (deficit)	$	224,876		$	151,795

The West Delta 61 and 62 blocks experienced an increase in oil and natural gas production in the first quarter of 2005 due to initial flush production from new wells that came online in the third quarter of 2004. The PNR-operated wells ceased production in 2002, and the wells were plugged and abandoned by year-end with the facilities being completely abandoned during 2003. The only remaining wells on this block are in West Delta 61. PNR farmed out a portion of West Delta 61 to Stone retaining a 12.5% (11.25% net to the Trust) overriding royalty interest.

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Capital Expenditures

PNR does not anticipate any significant capital expenditures on the Royalty Properties in the future. Due to the limited financial capacity of the Trust, PNR has advised that it intends to farm out the Trust’s interest in the blocks it believes may be produced economically, retaining an overriding royalty interest for the Trust.

Abandonment Expenditures

The table below provides a rollforward of the abandonment and removal costs cash reserve that PNR has withheld from the Trust:

Balance, December 31, 2004	$	2,676,149
Abandonment cost incurred	(553,041		)
Balance, March 31, 2005	$	2,123,108

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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			West Delta 61 and 62			Total
Three Months Ended March 31, 2005:
Ninety percent of gross proceeds	$	36,081		$	236,217		$	272,298
Less ninety percent of—
Operating expenditures	(28,439		)	(11,341		)	(39,780		)
Capital costs recovered	—			—			—
Net proceeds (deficit)	$	7,642		$	224,876		$	232,518
Trust share of net proceeds (99.99%)							$	232,495
Recoupment of deficit							(59,035		)
Royalty income							173,460
Trust deficit							$	—
Production Volumes and Average Prices:
Crude oil, condensate and natural gas liquids (Bbls)	16			2,358			2,374
Average sales price per Bbl	$	45.27		$	41.66		$	41.69
Natural gas (Mcf)	7,068			23,357			30,425
Average sales price per Mcf	$	5.00		$	5.91		$	5.70
Producing wells	1			4			5
Three Months Ended March 31, 2004:
Ninety percent of gross proceeds	$	90,524		$	150,417		$	240,941
Less ninety percent of—
Operating expenditures	(89,600		)	1,378			(88,222		)
Capital costs recovered	—			—			—
Net proceeds (deficit)	$	924		$	151,795		$	152,719
Trust share of net proceeds (99.99%)							$	152,704
Increase in deficit							(152,704		)
Royalty income							—
Trust deficit							$	(544,008	)
Production Volumes and Average Prices:
Crude oil, condensate and natural gas liquids (Bbls)	—			3,507			3,507
Average sales price per Bbl	$	—		$	27.93		$	27.93
Natural gas (Mcf)	18,295			11,452			29,747
Average sales price per Mcf	$	4.95		$	4.58		$	4.81
Producing wells	1			3			4

The amounts shown are for Mesa Offshore Royalty Partnership. Producing wells indicate the number of wells capable of production as of the end of the period. The amounts for the three months ended March 31, 2005 and 2004 represent actual production for the periods November 2004 through January 2005 and November 2003 through January 2004, 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. The unexpended amount withheld by PNR for future abandonment costs at March 31, 2005 was $2,123,108. The Trust deficit balance of $1,594,059 as of March 31, 2005 will be deducted from any future gross proceeds on the Royalty properties, which deduction will reduce future Royalty income. This amount to be recouped has decreased from $1,623,151

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at December 31, 2004 due to the generation of $29,092 of Royalty income in excess of general and administrative expenses of the Trust.

Production and Price Review

Production volumes for natural gas increased to 30,425 Mcf in the first quarter 2005 as compared with 29,747 Mcf in the first quarter 2004 primarily due to increased production at West Delta 61 and 62 due to the Stone wells coming back on-line which were partially offset by the shutting down of the Brazos A-39 No. A-3 well. The average sales price received for natural gas in the first quarter 2005 was $5.70 per Mcf as compared with $4.81 per Mcf in the first quarter 2004. Crude oil, condensate and natural gas liquids production volumes decreased to 2,374 barrels in the first quarter 2005 as compared to 3,507 barrels in the first quarter 2004. The average sales price in the first quarter 2005 for crude oil, condensate and natural gas liquids was $41.69 per barrel as compared to $27.93 per barrel in the first quarter 2004.

Termination 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. As a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture.

The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no discretion regarding the occurrence of the Termination Threshold or its consequences.

The Trust Indenture provides the Trustee a two-year period during which it must sell all of the Trust properties. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee expects that the sale process will be open to any persons desiring to participate, but, as is customary, access to information and participation may be limited to persons who execute confidentiality agreements regarding information provided by the working interest owners. The Trustee may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a “public” auction in the sense that it may not be open to anyone who does not satisfy these requirements. The Trustee is currently reviewing a potential online bidding process for participants in order to provide current public information on bidding to the marketplace. The Trustee will also determine a duration of bidding that it deems in the best interest of the unitholders. See Note 2 for discussion on Status of the Trust.

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, N.A., as Trustee of the Trust, and

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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 disclosure controls and procedures have not been effective to present timely the changes in the presentation of the financial statements within the bounds of liquidation basis accounting, which the Trust was required to adopt effective January 1, 2005 and for the Trustee to receive timely information for the Trustee to derive its estimate of the fair value of the Royalty interest.

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 limitations in the scope of disclosure controls and procedures that are not subject to change or modification by the Trustee. The contractual limitations and reliance that may affect information included in this report 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.

·Under the terms of the Trust Agreement, the Trustee is entitled to rely, and in fact relies, on certain experts in good faith.

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 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 or the managing general partner of the Partnership.

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PART II

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 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)
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.

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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:	/s/ JPMORGAN CHASE BANK, N.A.,
		as Trustee
	By:	/s/ MIKE ULRICH
		Mike Ulrich
		Vice President
Date: May 20, 2005

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.

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