**SECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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FORM 10-Q

x        QUARTERLY REPORT PURSUANT TOSECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30,2004

**o        TRANSITION REPORT PURSUANT TOSECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _________ TO_________**

 

**Commissionfile number 1-8432**

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MESA OFFSHORE TRUST

(Exact name of Registrantas Specified in its Charter)

| **Texas**(State of Incorporation  or Organization)                                                                                | **76-6004065**(I.R.S. Employer  Identification No.) |
|-----------------------------------------------------------------------------------------------------------------------------------|-----------------------------------------------------|
| **JPMorgan Chase Bank, Trustee  Institutional Trust Services  700 Lavaca  Austin, Texas**(Address of Principal Executive Offices) | **78701**(Zip Code)                                 |

 

**1-800-852-1422/ 1-512-479-2562**

(Registrant’s TelephoneNumber, Including Area Code)

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Indicate by check mark whetherthe registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required tofile such reports), and (2) hasbeen subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by a check mark whether the registrant is anaccelerated filer (as defined in Rule 12b-2 of theAct). Yes o  No x

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

Asof November 14, 2004— 71,980,216 Units of BeneficialInterest in Mesa Offshore Trust.

 

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**PART I—FINANCIAL INFORMATION**

***Item 1.*FinancialStatements.**

**MESAOFFSHORE TRUST**

**STATEMENTS OFDISTRIBUTABLE INCOME(Unaudited)**
| ** **                          | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                          | ** ** | **2004**                                             | ** ** | **2003**                                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| Royalty income                      |       | $                                                    | —     |                                                | $          | — |   | $ | — |   | $ | — |   |
| Interest income                     |       | 1,039                                                |            | 1,741                                               |       | 3,663 |   | 7,566 |   |
| General and  administrative expense |       | (1,039                                               | )          | (1,741                                              | )          | (3,663 | ) | (7,566 | ) |
| Distributable income                |       | $                                                    | —     |                                                | $          | — |   | $ | — |   | $ | — |   |
| Distributable  income per unit      |       | $                                                    | —     |                                                | $          | — |   | $ | — |   | $ | — |   |

 

**STATEMENTSOF ASSETS, LIABILITIES AND TRUST CORPUS**
| ** **                                                                         | ** ** | **September 30,  2004** | ** ** | **December 31,  2003** | ** ** |
|------------------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                                         | ** ** | **(Unaudited)**              | ** ** | ** **                  | ** ** |
| ASSETS                                                                             |       |                         |       |                        |       |
| Cash and short-term  investments                                                   |       | $                            | 478,670    |                        | $          | 938,827 |   |
| Interest  receivable                                                               |       | 330                          |       | 1,603                       |       |
| 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                                                                       |       | $                            | 490,127    |                        | $          | 951,557 |   |
| LIABILITIES AND TRUST CORPUS                                                       |       |                         |       |                        |       |
| Reserve for Trust  expenses                                                        |       | $                            | 479,000    |                        | $          | 940,430 |   |
| Distributions  payable                                                             |       | —                       |       | —                      |       |
| Trust corpus  (71,980,216 units of beneficial interest authorized and outstanding) |       | 11,127                       |       | 11,127                      |       |
| Total liabilities  and trust corpus                                                |       | $                            | 490,127    |                        | $          | 951,557 |   |

 

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

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**MESA OFFSHORE TRUST**

**STATEMENTS OFCHANGES IN TRUST CORPUS(Unaudited)**
| ** **                                      | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                      | ** ** | **2004**                                             | ** ** | **2003**                                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| Trust corpus,  beginning of period              |       | $                                                    | 11,127     |                                                | $          | 11,127 |   | $ | 11,127 |   | $ | 11,127 |   |
| Distributable income                            |       | —                                               |       | —                                              |       | — |   | — |   |
| Distributions to unitholders                    |       | —                                               |       | —                                              |       | — |   | — |   |
| Amortization of net overriding royalty interest |       | —                                               |       | —                                              |       | — |   | — |   |
| Trust corpus, end of  period                    |       | $                                                    | 11,127     |                                                | $          | 11,127 |   | $ | 11,127 |   | $ | 11,127 |   |

 

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

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**MESAOFFSHORE 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, MesaPetroleum Co., predecessor to Mesa Limited Partnership, which was the predecessorto MESA Inc., transferred to the Trust a 99.99% interest in the MesaOffshore Royalty Partnership (the “Partnership”). The Partnership was createdto receive and hold a net overriding royalty interest (the “Royalty”) in tenproducing and nonproducing oil and gas properties located in federal watersoffshore Louisiana and Texas (the “Royalty Properties”). MESA Inc. createdthe Royalty out of its working interest in the Royalty Properties andtransferred it to the Partnership. Until August 7, 1997, MESA Inc.owned and operated its assets through Mesa Operating Co. (“Mesa”), the operatorand 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 managinggeneral partner of the Partnership. As used in this report, the term PNRgenerally refers to the operator of the Royalty Properties, unless otherwiseindicated.

**Statusof the Trust**

The Trust Indenture provides that the Trust willterminate if the total amount of cash per year received by the Trust fallsbelow certain levels for each of three successive years (the “TerminationThreshold”).

 As a result of the Trustproperties nearing the end of their estimated productive lives, Royalty incomereceived by the Trust in 2002 and 2003 fell below the Termination Thresholdprescribed by the Trust Indenture. In addition, there is an accumulated deficitdue PNR as of September 30, 2004 of $331,267 that will be deductedfrom any future gross proceeds on the Royalty Properties, which deduction willreduce future Royalty income.

TheDecember 31, 2003 reserve report prepared for the Partnership indicatesthat Royalty income expected to be received by the Trust in 2004 will be belowthe Termination Threshold. The Termination Threshold for 2003 was approximately$1.2 million. The reserve report estimates that future Royalty income tothe Trust will be zero for 2004 as estimated net proceeds from the Trustproperties during 2004 will not be sufficient to recoup the accumulated deficitexisting at December 31, 2003. In addition, the reserve report estimatesthat future Royalty income to the Trust after 2004 will be approximately$2.2 million (net of the recoupment of the Trust deficit). Future Royaltyincome in the reserve report was calculated using oil and natural gas spotprices in effect at December 31, 2003 of $31.42 per barrel and $5.97 perMcf, respectively. Based on the current estimates of future Royalty income and2004 operational updates received from PNR, the Trustee continues to expect that Royaltyincome received by the Trust will fall below the Termination Threshold in 2004.**Accordingly, the Trustee anticipates that effectiveafter December 31, 2004, the Trust Indenture will require the Trustee to sellthe Trust’s interest in the Partnership, or cause the Partnership to sell theassets of the Partnership, and thereby terminate the Trust.**

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Assuming the TerminationThreshold is not met as of December 31, 2004, the Trust Indenture provides the Trusteea two-year period during which it must sell all of the Trust properties. TheTrust Indenture provides that such properties must be sold for cash and not forany other consideration. The Trustee may sell the properties at public auctionto the highest cash bidder, but it may also conduct any other sale process thatit deems in the best interest of the Unitholders. The Trustee currently intendsto commence a sale process promptly in early 2005 assuming commodity andfinancial market conditions remain favorable for the timing of a sale. TheTrustee has engaged an independent party to commence a joint venture audit andhas made requests for other relevant information in anticipation of this saleprocess and the termination of the Trust.

PNR advised the Trust that it farmed out the Trust’sinterest in Brazos A-7 and A-39 so that two exploratory prospectscould be drilled during 2003 with the Trust retaining an overriding royaltyinterest. The first exploration prospect was drilled on Brazos A-7 during2003 and was determined to be a dry hole. As such, the well was plugged andabandoned. The second exploration prospect was drilled on Brazos A-39 andhas been announced as a discovery. PNR has approved a plan to set minimalfacilities, complete the well and perform a production test prior todetermining whether or not to develop the project as a subsea tie-back into anexisting platform. Equipment has been ordered and the production test shouldtake place in late 2004. If the discovery is deemed to be commercially viable,first sales will not take place until 2005,which may occur after the termination of theTrust. In addition, PNR advised the Trust that Stone Energy Corporation (“Stone”)recently completed an exploratory well on WestDelta 61 that was placed on production early in the thirdquarter of 2004. Even with this well coming on-line in 2004, it iscurrently expected that any Royalty income generated from this prospect willnot be received in time to eliminate the deficit balance and increase Royaltyincome above the TerminationThreshold.

There are numerous uncertainties inherent inestimating and projecting the quantity and value of proved reserves for theTrust properties, as many of the Trust properties are nearing the end of theirproductive lives and are therefore subject to unforeseen changes in productionrates. As such, the foregoing statements reflect only current reasonableexpectations.

The terms of the FirstAmended and Restated Articles of General Partnership of the Partnership providethat the Partnership shall dissolve upon the occurrence of any of thefollowing: (a) December 31, 2030; (b) the election of theTrustee to dissolve the Partnership; (c) the termination of the Trust; (d) thebankruptcy of the Managing General Partner; or (e) the dissolution of theManaging General Partner or its election to dissolve the Partnership; providedthat the Managing General Partner shall not elect to dissolve the Partnershipso long as the Trustee remains the only other partner of the Partnership. Inthe event of a dissolution of the Partnership and a subsequent winding up andtermination thereof, the assets of the Partnership (i.e., the Royalty interest)could either (i) be distributed in kind ratably to the Managing GeneralPartner and the Trustee or (ii) be sold and the proceeds thereofdistributed ratably to the Managing General Partner and the Trustee. In theevent of a sale of the Royalty and a distribution of the cash proceeds to theTrustee, the Trustee would make a final distribution to unitholders of suchcash proceeds plus any other cash held by the Trust after the payment of orprovision for all liabilities of the Trust, and the Trust would be terminated.

**Note 2—Basis of Presentation**

The accompanying unauditedfinancial information has been prepared by JPMorgan Chase Bank (the “Trustee”)in accordance with the instructions to Form 10-Q. JPMorgan ChaseBank was formerly known 

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as TheChase Manhattan Bank and is the successor by mergers to the original name ofthe Trustee, Texas Commerce Bank National Association. The Trustee believessuch information includes all the disclosures necessary to make the informationpresented not misleading. The information furnished reflects all adjustmentswhich are, in the opinion of the Trustee, necessary for a fair presentation ofthe results for the interim periods presented. The financial information shouldbe read in conjunction with the financial statements and notes thereto includedin the Trust’s 2003 Annual Report on Form 10-K.

Thefinancial statements of the Trust are prepared on the following basis:

(a)    Royalty income recorded for a month is the Trust’s interest inthe amount computed and paid by the working interest owner to the Partnershipfor such month rather than either the value of a portion of the oil and gasproduced by the working interest owner for such month or the amountsubsequently determined to be 90% of the net proceeds for such month;

(b)   Interest income, interest receivable and distributions payable tounitholders include interest to be earned on short-term investments from thefinancial 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 iscalculated on the basis of current royalty income in relation to estimatedfuture royalty income, is charged directly to trust corpus since such amountdoes not affect distributable income; and

(e)    Distributions payable are determined on a monthly basis and arepayable to unitholders of record as of the last business day of each month orsuch other day as the Trustee determines is required to comply with legal orstock exchange requirements. However, cash distributions are made quarterly inJanuary, April, July and October, and include interest earned from themonthly record dates to the date of distribution.

This basis for reportingRoyalty income is considered to be the most meaningful because distributions tothe unitholders for a month are based on net cash receipts for such month.However, it will differ from the basis used for financial statements preparedin accordance with accounting principles generally accepted in the UnitedStates of America because under such accounting principles, Royalty income fora month would be based on net proceeds from production for such month withoutregard to when calculated or received and interest income for a month would becalculated only through the end of such month.

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

Generally, net proceedsmeans the excess of the amounts received by the working interest owner fromsales of oil and gas from the Royalty Properties plus other cash receipts overoperating and capital costs incurred. For the three and ninemonths ending September 30, 2004, proceeds from oil and gas sales exceededoperating and capital costs incurred; however, no Royalty income was reportedas the net proceeds were used to reduce the accumulated deficit. For the threemonths ended September 30, 2004, the deficit was reduced by $102,641. There remains anaccumulated deficit balance due PNR as of September 30, 2004 of $331,267 that will be deducted fromany future gross proceeds on the Royalty Properties, which deduction willreduce future Royalty income. In addition, no Royalty income will bedistributed to unitholders until the Trustee recoups Trust expenses being paidfrom the reserve that the 

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Trusteehas established for anticipated future expenses. As of September 30, 2004,the Reserve for Trust expenses is $479,000. As of September 30, 2004 the Trustee wouldexpect to withhold up to $1,521,000 from future Royaltyincome before Trust distributions will resume.

Since the inception of theTrust, PNR has withheld from royalty income amounts for the future abandonmentof the Royalty properties. The unexpended amount withheld by PNR for futureabandonment costs at September 30, 2004 was $2,679,372. Under the terms of the Royalty conveyance, theamounts withheld by PNR for future abandonment costs are not escrowed and donot accrue interest for thebenefit of the Trust.

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***Item 2.*Management’sDiscussion and Analysis of Financial Condition and Results of Operations.**

The following review ofthe Trust’s financial condition and results of operations should be read inconjunction with the financial statements and notes thereto.

**Note Regarding Forward-Looking Statements**

This Form 10-Qincludes “forward-looking statements” within the meaning of Section 27Aof the Securities Act of 1933, as amended, and Section 21E of theSecurities Exchange Act of 1934, as amended. All statements other thanstatements of historical facts included in this Form 10-Q, includingwithout limitation the statements under “Management’s Discussion and Analysisof Financial Condition and Results of Operations” and Note 1 to thefinancial statements of the Trust regarding the future net revenues of theTrust, are forward-looking statements. Although Pioneer has advised theTrust that it believes that the expectations reflected in such forward-lookingstatements are reasonable, no assurance can be given that such expectationswill prove to have been correct. Important factors that could cause actualresults to differ materially from expectations (“Cautionary Statements”) aredisclosed in this Form 10-Q, and in the Trust’s Form 10-K for the year ended December 31, 2003,including under the section “Business—Principal Trust Risk Factors.” Allsubsequent written and oral forward-looking statements attributable tothe Trust or persons acting on its behalf are expressly qualified in theirentirety by the Cautionary Statements.

**FinancialReview**

The amount of cash distributed by the Trust isdependent on, among other things, the sales prices and quantities of gas, crudeoil, condensate and natural gas liquids produced from the Royalty Propertiesand the quantities sold. Substantial uncertainties exist with regard to futuregas and oil prices, which are subject to fluctuations due to the regionalsupply and demand for natural gas and oil, production levels and otheractivities 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.

Belowis a summary of Royalty income received on the Trust properties for the threeand nine monthsendedSeptember 30, 2004 and 2003:
| ** **                                         | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|----------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                         | ** ** | **2004**                                             | ** ** | **2003**                                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| Gross proceeds @  90%                              |       | $                                                    | 129,251    |                                                | $          | 289,855 |   | $ | 513,492 |   | $ | 719,983 |   |
| Operating  expenditures @ 90%                      |       | (26,599                                              | )          | (289,855                                            | )          | (148,010 | ) | (719,983 | ) |
| Capital  expenditures @ 90%                        |       | —                                               |       | —                                              | )          | — |   | — |   |
| Net proceeds  (deficit)                            |       | 102,652                                              |       | —                                              |       | 365,482 |   | — |   |
| Increase  (decrease) in deficit due PNR            |       | (102,641                                             | )          | (—                                             | )          | (365,445 | ) | (— | ) |
| Net proceeds  after deficit recovery               |       | —                                               |       | —                                              |       | — |   | — |   |
| Royalty Income  (99.99%)                           |       | $                                                    | —     |                                                | $          | — |   | $ | — |   | $ | — |   |
| Accumulated deficit due  PNR (as of end of period) |       | $                                                    | (331,267   | )                                                   | $          | (615,553 | ) | $ | (331,267 | ) | $ | (615,553 | ) |

 

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Belowis a summary of distributable income for the three and ninemonthsendedSeptember 30, 2004 and 2003:
| ** **                               | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                               | ** ** | **2004**                                             | ** ** | **2003**                                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| Royalty income                           |       | $                                                    | —     |                                                | $          | — |   | $ | — |   | $ | — |   |
| Interest income                          |       | 1,039                                                |       | 1,741                                               |       | 3,663 |   | 7,566 |   |
| General and  administrative expenses     |       | (1,039                                               | )          | (1,741                                              | )          | (3,663 | ) | (7,566 | ) |
| Distributable  income                    |       | $                                                    | —     |                                                | $          | — |   | $ | — |   | $ | — |   |
| Distributable  income per unit           |       | $                                                    | —     |                                                | $          | — |   | $ | — |   | $ | — |   |
| Recoupment of reserve for Trust expenses |       | $                                                    | 102,641    |                                                | $          | — |   | $ | 365,445 |   | $ | — |   |

 

The Trust had nodistributable income for the three and nine monthsendedSeptember 30, 2004 and 2003. Since December 2001, the Trust has beenin a deficit position to PNR as a result of significant decline in productionon properties in which the Trust has a Royalty interest. The Trustcontinues to be in a deficit position as a result of lower production on allproperties due to these properties nearing the end of their productive lives.See “—Operational Review” below.

**Operational Review**

PNR has advised the Trustthat during the third quarter of 2004 its offshore gas production was marketedunder short-term contracts at spot market prices primarily to TotalS.A. and that it expects to continue to market its production under short-termcontracts for the foreseeable future. Spot market prices for natural gas in thethird quarter of 2004 were generally higher than spot market prices in thethird quarter of 2003.

The amount of cashdistributed by the Trust is dependent on, among other things, the sales pricesand quantities of gas, crude oil and condensate produced from the RoyaltyProperties and the quantities sold. Substantial uncertainties exist with regardto future gas and oil prices, which are subject to fluctuations due to theregional supply and demand for natural gas and oil, production levels and otheractivities 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 operationalreview of the remaining producing Trust properties:

***Brazos A-7 and A-39***
| ** **                    | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                    | ** ** | **2004**                                             | ** ** | **2003**                                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| Gross proceeds @  90%         |       | $                                                    | 32,713     |                                                | $          | 75,128 |   | $ | 132,165 |   | $ | 281,730 |   |
| Operating  expenditures @ 90% |       | (23,970                                              | )          | (75,128                                             | )          | (146,014 | ) | (281,730 | ) |
| Capital  expenditures @ 90%   |       | —                                               |       | —                                              |       |   |   | — |   |
| Net proceeds  (deficit)       |       | $                                                    | 8,743      |                                                     | $          | — |   | $ | (13,849 | ) | $ | — |   |
| Producing wells               |       | 1                                                    |       | 2                                                   |       | 1 |   | 2 |   |

 

The Brazos A-7 and A-39 blocks continued to experiencea decrease in natural gas production due to natural production decline. As of September 30,2004, these two blocks had one well producing, the Brazos A-7 No. B-1well. The Brazos A-39 No. A-3 well ceased production during the fourthquarter of 2003. PNR 

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farmedout the Trust’s interest in both of these blocks so that two explorationprospects could be drilled with the Trust retaining an overriding royaltyinterest. The first prospect on Brazos A-7 was drilled during 2003 and wasdetermined to be a dry hole. As such, the well was plugged and abandoned. Thesecond exploration prospect was drilled on Brazos A-39 and has been announced as adiscovery. PNR has approved a plan to set minimal facilities, complete the welland perform a production test prior to determining whether or not to developthe project as a subsea tie-back into an existing platform. Equipment has beenordered and the production test should take place in late 2004. If the discoveryis deemed to be commercially viable, first sales will not take place until 2005, which may occur after the termination of theTrust. The plugging and abandonment of the PNR operated wells in theBrazos A-7 and Brazos A-39 blocks, with the exception of therecently drilled exploration well on the Brazos A-39 prospect, will begin inthe fourth quarter of 2004 and the PNR operated Brazos A-7 and Brazos A-39platforms will be removed in 2005.

***West Delta 61 and62***
| ** **                    | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                    | ** ** | **2004**                                             | ** ** | **2003**                                            | ** ** | **2004** | ** ** | **2003** | ** ** |
| Gross proceeds @ 90%          |       | $                                                    | 96,538     |                                                | $          | 214,727 |   | $ | 381,327 |   | $ | 438,253 |   |
| Operating expenditures @  90% |       | (2,629                                               | )          | (214,727                                            | )          | (1,996 | ) | (438,253 | ) |
| Capital expenditures @  90%   |       | —                                               |       | —                                              |       | — |   | — |   |
| Net proceeds (deficit)        |       | $                                                    | 93,909     |                                                | $          | — |   | $ | 379,331 |   | $ |   |   |
| Producing wells               |       | 4                                                    |       | 3                                                   |       | 4 |   | 3 |   |

 

The West Delta 61 and 62blocks experienced a decrease in oil and natural gas production in the thirdquarter of 2004 as compared to the same period in 2003 due to naturalproduction decline. The producing wells are operated by Stone. The PNR-operatedwells ceased production in 2002, and the wells were plugged and abandoned at the end of 2002 with thefacilities being completely abandoned during 2003. The only remaining wells onthis block are in West Delta 61. PNR farmed out a portion of West Delta 61 toStone retaining a 12.5% (11.25% net to the Trust) overriding royalty interest.Stone recently completed drilling an exploratory well that was placed onproduction early in the third quarter of 2004. Even with this well coming on-line in 2004, it iscurrently expected that any Royalty income generated from this prospect willnot be received in time to eliminate the deficit balance and increase Royaltyincome above the TerminationThreshold.

***CapitalExpenditures***

PNR does not anticipate making any significant capitalexpenditures on the Royalty Properties in the future. Due to the limitedfinancial capacity of the Trust, PNR has advised that it intends to farm outthe Trust’s interest in the blocks that PNR believes may be producedeconomically, retaining an overriding royalty interest for the Trust.

***AbandonmentExpenditures***

Thetable below provides a rollforward of the abandonment and removal costs that PNR haswithheld from the Trust. Under the terms of the Royalty conveyance, theseamounts withheld are not escrowed and do not accrue interest for the benefit ofthe Trust.
| Balance,  December 31, 2003          |   | $        | 2,800,643 |   |
|-------------------------------------------|--------|----------|-----------|--------|
| Abandonment cost  incurred (WD 61 and 62) |   | (121,271 | )         |
| Balance, September 30, 2004          |   | $        | 2,679,372 |   |

 

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Thefollowing tables provide a summary of the calculations of the net proceedsattributable to the Partnership’s royalty interest (unaudited):
| ** **                                           | ** ** | **Brazos A-7  and A-39** | ** ** | **West Delta  61 and 62** | ** ** | **Total** | ** ** |
|------------------------------------------------------|------------|------------------------------------|------------|------------------------------------------|------------|-----------|------------|
| **Three Months Ended September  30, 2004:**          |       |                               |       |                                     |       |      |       |
| Ninety percent of gross proceeds                     |       | $                                  | 32,713     |                                     | $          | 96,538    |       | $ | 129,251 |   |
| Less ninety  percent of—                        |       |                               |       |                                     |       |      |       |
| Operating expenditures                               |       | (23,970                            | )          | (2,629                                   | )          | (26,599   | )          |
| Capital costs recovered                              |       | —                             |       | —                                   |       | —    |       |
| Net proceeds                                         |       | $                                  | 8,743      |                                          | $          | 93,909    |       | $ | 102,652 |   |
| Trust share of net proceeds (99.99%)                 |       |                               |       |                                     |       | $         | 102,641    |   |
| Recoupment of deficit                                |       |                               |       |                                     |       | (102,641  | )          |
| Royalty income                                       |       |                               |       |                                     |       | —    |       |
| Trust Deficit                                        |       |                               |       |                                     |       | $         | 331,267    |   |
| Production Volumes and  Average Prices:              |       |                               |       |                                     |       |      |       |
| Crude oil, condensate and natural gas liquids (Bbls) |       | 6                                  |       | 1,565                                    |       | 1,571     |       |
| Average sales price per Bbl                          |       | $                                  | 37.33      |                                     | $          | 35.83     |       | $ | 35.84 |   |
| Natural gas (Mcf)                                    |       | 5,280                              |       | 7,552                                    |       | 12,832    |       |
| Average sales price per Mcf                          |       | $                                  | 6.16       |                                     | $          | 5.35      |       | $ | 5.68 |   |
| Producing wells                                      |       | 1                                  |       | 4                                        |       | 5         |       |
| **Three Months Ended  September 30, 2003:**     |       |                               |       |                                     |       |      |       |
| Ninety percent of gross proceeds                     |       | $                                  | 75,128     |                                     | $          | 214,727   |       | $ | 289,855 |   |
| Less ninety  percent of—                        |       |                               |       |                                     |       |      |       |
| Operating expenditures                               |       | (75,128                            | )          | (214,727                                 | )          | (289,855  | )          |
| Capital costs recovered                              |       | —                             |       | —                                   |       | —    |       |
| Net proceeds (deficit)                               |       | $                                  | —     |                                     | $          | —    |       | $ | — |   |
| Trust share of net proceeds (99.99%)                 |       |                               |       |                                     |       | $         |       |   |
| Increase in deficit                                  |       |                               |       |                                     |       | —    |       |
| Royalty income                                       |       |                               |       |                                     |       | —    |       |
| Trust Deficit                                        |       |                               |       |                                     |       | (615,553  | )          |
| Production Volumes and  Average Prices:              |       |                               |       |                                     |       |      |       |
| Crude oil, condensate and natural gas liquids (Bbls) |       | 183                                |       | 2,526                                    |       | 2,709     |       |
| Average sales price per Bbl                          |       | $                                  | 27.69      |                                     | $          | 28.99     |       | $ | 28.90 |   |
| Natural gas (Mcf)                                    |       | 13,773                             |       | 20,102                                   |       | 33,875    |       |
| Average sales price per Mcf                          |       | $                                  | 5.09       |                                     | $          | 7.04      |       | $ | 6.25 |   |
| Producing wells                                      |       | 2                                  |       | 3                                        |       | 5         |       |

 

Theamounts shown are for Mesa Offshore Royalty Partnership. Producing wellsindicate the number of wells capable of production as of the end of the period.The amounts for the three months ended September 30, 2004 and 2003represent actual production for the periods May 2004 through July2004 and May 2003through July 2003, respectively. Capitalcosts recovered represent capitalcosts incurred during the current or prior periods to the extent that suchcosts have been recovered by PNR from current period Gross Proceeds. Theunexpended amount withheld by PNR for future abandonment costs at 

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September 30, 2004 was $2,679,372. The Trust deficitbalance due PNR of $331,267 asof September 30, 2004 will be deducted from any future gross proceeds onthe Royalty properties, which deduction will reduce future Royalty income. Asof September 30, 2004, the Trustee would expectto withhold up to $1,521,000from Royalty income before Trust distributions will resume.
| ** **                                           | ** ** | **Brazos A-7  and A-39** | ** ** | **West Delta  61 and 62** | ** ** | **Total** | ** ** |
|------------------------------------------------------|------------|------------------------------------|------------|------------------------------------------|------------|-----------|------------|
| **Nine Months Ended  September 30, 2004:**      |       |                               |       |                                     |       |      |       |
| Ninety percent of gross proceeds                     |       | $                                  | 132,165    |                                     | $          | 381,327   |       | $ | 513,492 |   |
| Less ninety  percent of—                        |       |                               |       |                                     |       |      |       |
| Operating expenditures                               |       | (146,014                           | )          | (1,996                                   | )          | (148,010  | )          |
| Capital costs recovered                              |       | —                             |       | —                                   |       | —    |       |
| Net proceeds (deficit)                               |       | $                                  | (13,849    | )                                        | $          | 379,331   |       | $ | 365,482 |   |
| Trust share of net proceeds (99.99%)                 |       |                               |       |                                     |       | $         | 365,445    |   |
| Recoupment of deficit                                |       |                               |       |                                     |       | (365,445  | )          |
| Royalty income                                       |       |                               |       |                                     |       | —    |       |
| Trust Deficit                                        |       |                               |       |                                     |       | $         | 331,267    |   |
| Production Volumes and  Average Prices:              |       |                               |       |                                     |       |      |       |
| Crude oil, condensate and natural gas liquids (Bbls) |       | 24                                 |       | 7,514                                    |       | 7,538     |       |
| Average sales price per Bbl                          |       | $                                  | 35.30      |                                     | $          | 31.05     |       | $ | 31.07 |   |
| Natural gas (Mcf)                                    |       | 24,067                             |       | 29,163                                   |       | 53,230    |       |
| Average sales price per Mcf                          |       | $                                  | 5.46       |                                     | $          | 5.07      |       | $ | 5.25 |   |
| Producing wells                                      |       | 1                                  |       | 4                                        |       | 5         |       |
| **Nine Months Ended  September 30, 2003:**      |       |                               |       |                                     |       |      |       |
| Ninety percent of gross proceeds                     |       | $                                  | 281,730    |                                     | $          | 438,253   |       | $ | 719,983 |   |
| Less ninety  percent of—                        |       |                               |       |                                     |       |      |       |
| Operating expenditures                               |       | (281,730                           | )          | (438,253                                 | )          | (719,983  | )          |
| Capital costs recovered                              |       | —                             |       | —                                   |       | —    |       |
| Net proceeds (deficit)                               |       | $                                  | —     |                                     | $          | —    |       | $ | — |   |
| Trust share of net proceeds (99.99%)                 |       |                               |       |                                     |       | $         | —     |   |
| Increase in deficit                                  |       |                               |       |                                     |       | —    |       |
| Royalty income                                       |       |                               |       |                                     |       | —    |       |
| Trust Deficit                                        |       |                               |       |                                     |       | $         | (615,553   | ) |
| Production Volumes and  Average Prices:              |       |                               |       |                                     |       |      |       |
| Crude oil, condensate and natural gas liquids (Bbls) |       | 306                                |       | 5,186                                    |       | 5,492     |       |
| Average sales price per Bbl                          |       | $                                  | 27.37      |                                     | $          | 26.87     |       | $ | 26.90 |   |
| Natural gas (Mcf)                                    |       | 66,857                             |       | 48,823                                   |       | 110,680   |       |
| Average sales price per Mcf                          |       | $                                  | 4.09       |                                     | $          | 6.82      |       | $ | 5.17 |   |
| Producing wells                                      |       | 2                                  |       | 3                                        |       | 5         |       |

 

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The amounts shown are forMesa Offshore Royalty Partnership. Producing wells indicate the number of wellscapable of production as of the end of the period. The amounts for the ninemonthsendedSeptember 30, 2004 and 2003 represent actual production for the periods November 2003through July 2004 and November 2002through July 2003, respectively.Capital costs recovered representcapital costs incurred during the current or prior periods to the extent thatsuch costs have been recovered by PNR from current period Gross Proceeds. Theunexpended amount withheld by PNR for future abandonment costs at September 30,2004 was $2,679,372. The Trust deficitbalance due PNR of $331,267 as of September 30,2004 will be deducted from any future gross proceeds on the Royalty properties,which deduction will reduce future Royalty income. As of September 30,2004, the Trustee would expectto withhold up to $1,521,000from Royalty income before trust distributions will resume.

***Production and Price Review***

Production volumes for natural gas decreased to 12,832 Mcf in the third quarter of2004 as compared with 33,875 Mcf in the third quarter of 2003. The averagesales price received for natural gas in the third quarter of 2004 was $5.68 per Mcf as compared with$6.25 per Mcf in the third quarter of 2003. Crude oil, condensate and naturalgas liquids production volumes decreased to 1,571 barrels in the third quarterof 2004 as compared to 2,709 barrels in the third quarter of 2003. The averagesales price in the third quarter of 2004 for crude oil, condensate and naturalgas liquids was $35.84 per barrel as compared with$28.90 per barrel in the third quarter of 2003.

Production volumes fornatural gas decreased to 53,230 Mcf for the ninemonthsendedSeptember 30, 2004 as compared with 110,680 Mcf for the ninemonthsendedSeptember 30, 2003. The average sales price received for natural gas forthe nine monthsendedSeptember 30, 2004 was $5.25 per Mcf as compared with$5.17 per Mcf for the nine monthsendedSeptember 30, 2003. Crude oil, condensate and natural gas liquidsproduction volumes increased to 7,538 barrels for theninemonthsendedSeptember 30, 2004 as compared to 5,492 barrels for the ninemonthsendedSeptember 30, 2003. The average sales price for the ninemonthsendedSeptember 30, 2004 for crude oil, condensate and natural gas liquids was $31.07 per barrel as compared with$26.90 per barrel for the nine monthsended  September 30, 2003.

**Termination of the Trust**

The terms of the Mesa Offshore Trust Indentureprovide, among other things, that the Trusteemust sell of the Trust’s interest in the Partnership, or cause the Partnershipto sell all of its assets, and thereby to terminate the Trust, afterthe first to occur of the following events: (1) the total amount of cashreceived per year by the Trust for each of three successive years commencingafter December 31, 1987 is less than ten times one-third of thetotal amount payable to the Trustee as compensation for such three-yearperiod (the “Termination Threshold”) or (2) a vote by holders of amajority of the outstanding units in favor of termination. Because the Trustwill terminate in the event the total amount of cash received per year by theTrust falls below certain levels, it would be possible for the Trust toterminate even though some of the Royalty Properties continued to haveremaining productive lives. For information regarding the estimated remaininglife of each of the Royalty Properties and the estimated future net revenues ofthe Trust based on information provided by PNR, see the Trust’s 2003 AnnualReport on Form 10-K and thedescription below. Upon termination of the Trust, the Trusteewill sell for cash all the assets held in the Trust estate and make a finaldistribution to unitholders of any funds remaining after all Trust liabilitieshave been satisfied. The discussion set forth above is qualified in itsentirety by reference to the Trust Indenture itself, 

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which is an exhibit to theTrust’s 2003 Annual Report on Form 10-K and is available uponrequest from the Trustee.

TheDecember 31, 2003 reserve report prepared for the Partnership indicatesthat Royalty income expected to be received by the Trust in 2004 will be belowthe Termination Threshold. The Termination Threshold for 2003 was approximately$1.2 million. The reserve report estimates that future Royalty income tothe Trust will be zero for 2004 as estimated net proceeds from the Trustproperties during 2004 will not be sufficient to recoup the accumulated deficitexisting at December 31, 2003. In addition, the reserve report estimatesthat future royalty income to the Trust after 2004 will be approximately$2.2 million (net of the recoupment of the Trust deficit). Future Royaltyincome in the reserve report was calculated using oil and natural gas spotprices in effect at December 31, 2003 of $31.42 per barrel and $5.97 perMcf, respectively. Based on the current estimates of future Royalty income and2004 operational updates received from PNR, the Trustee continues to expect that Royaltyincome received by the Trust will fall below the Termination Threshold in 2004.**Accordingly, the Trustee anticipates that effectiveafter December 31, 2004, the Trust Indenture will require theTrustee to sell the Trust’s interest in the Partnership, or cause thePartnership to sell the assets of the Partnership, and thereby terminate theTrust.**

Assuming the Termination Threshold is not met as ofDecember 31, 2004, the Trust Indenture provides the Trusteea two-year period during which it must sell all of the Trust properties. TheTrust Indenture provides that such properties must be sold for cash and not forany other consideration. The Trustee may sell the properties at public auctionto the highest cash bidder, but it may also conduct any other sale process thatit deems in the best interest of the Unitholders. The Trustee currently intendsto commence a sale process promptly in early 2005 assuming commodity and financialmarket conditions remain favorable for the timing of a sale. The Trustee hasengaged an independent party to commence a joint venture audit and has maderequests for other relevant information in anticipation of this sale processand the termination of the Trust.

PNR advised the Trust that it farmed out the Trust’sinterest in Brazos A-7 and A-39 so that two exploratory prospectscould be drilled during 2003 with the Trust retaining an overriding royaltyinterest. The first exploration prospect was drilled on Brazos A-7 during2003 and was determined to be a dry hole. As such, the well was plugged andabandoned. The second exploration prospect was drilled on Brazos A-39which has been announced as a discovery. PNR has approved a plan to set minimalfacilities, complete the well and perform a production test prior todetermining whether or not to develop the project as a subsea tie-back into anexisting platform. Equipment has been ordered and the production test shouldtake place in late 2004. If the discovery is deemed to be commercially viable,first sales will not take place until early 2005, which may occur after the termination ofthe Trust. In addition, PNR advised the Trust that Stone recently completed anexploratory well on West Delta 61that was placed on production early in the third quarter of 2004. Even with this well coming on-line,it is currently expected that any Royalty income generated from this prospectwill not be received in time to eliminate the deficit balance and increaseRoyalty income above the TerminationThreshold Amount.

The terms of the FirstAmended and Restated Articles of General Partnership of the Partnership providethat the Partnership shall dissolve upon the occurrence of any of thefollowing: (a) December 31, 2030; (b) the election of theTrustee to dissolve the Partnership; (c) the termination of the Trust; (d) thebankruptcy of the Managing General Partner; or (e) the dissolution of theManaging General Partner or its election to dissolve the Partnership; providedthat the Managing General Partner shall not elect to 

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dissolvethe Partnership so long as the Trustee remains the only other partner of thePartnership. In the event of a dissolution of the Partnership and a subsequentwinding up and termination thereof, the assets of the Partnership (i.e., theRoyalty interest) could either (i) be distributed in kind ratably to theManaging General Partner and the Trustee or (ii) be sold and the proceedsthereof distributed ratably to the Managing General Partner and the Trustee. Inthe event of a sale of the Royalty and a distribution of the cash proceeds tothe Trustee, the Trustee would make a final distribution to unitholders of suchcash proceeds plus any other cash held by the Trust after the payment of orprovision for all liabilities of the Trust, and the Trust would be terminated.

***Item 3.*Quantitative and Qualitative Disclosures About Market Risk.**

The Trust does not utilizemarket risk sensitive instruments. However, see the discussion of marketing byPNR above.

***Item 4.*Controlsand Procedures.**

*Evaluation of Disclosure Controlsand Procedures.  *The Trustee maintains disclosurecontrols and procedures designed to ensure that information required to bedisclosed by the Trust in the reports that it files or submits under theExchange Act of 1934, as amended, is recorded, processed, summarized and reportedwithin the time periods specified in the SEC’s rules and regulations.Disclosure controls and procedures include procedures designed to ensure thatinformation required to be disclosed by the Trust is accumulated andcommunicated by Pioneer, as the managing general partner of the Partnership,and the working interest owners to JPMorgan Chase Bank, as Trustee of theTrust, and its employees who participate in the preparation of the Trust’speriodic reports as appropriate to allow timely decisions regarding requireddisclosure.

As of the end of the period covered by this report,the Trustee carried out an evaluation of the Trustee’s disclosure controls andprocedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded thatthese controls and procedures are effective, while noting certain limitationson disclosure controls and procedures as set forth below.

Due to thecontractual arrangements of (i) the Trust Indenture, (ii) thePartnership Agreement and (iii) the rights of the Partnership under theConveyance regarding information furnished by the working interest owners,there are certain weaknesses that are not subject to change or modification bythe Trustee. The contractual limitations creating potential weaknesses indisclosure controls and procedures may be deemed to include:

·  The working interest owners alone control (i) historicaloperating data, including production volumes, marketing of products, operatingand capital expenditures, environmental and other liabilities, the effects ofregulatory changes and the number of producing wells and acreage, (ii) plansfor future operating and capital expenditures, (iii) geological datarelating to reserves, as well as the reserve report that contains projectedproduction, operating expenses and capital expenses, and (iv) informationrelating to projected production. The Trustee does not control this informationand relies entirely on the working interest owners to provide accurate andtimely information when requested for use in the Trust’s periodic reports.

·  The Trustee relies on information provided bythe managing general partner of the Partnership that is collected by themanaging general partner from the working interest owners. While the Trustee 

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may request informationthrough the managing general partner, the Conveyance together with thePartnership Agreement gives only the managing general partner of thePartnership, as the Royalty Owner, the actual authority and discretion torequest and receive financial information regarding the Royalty Properties fromthe working interest owners. While the Trustee requests material informationfor use in periodic reports as part of its disclosure controls and procedures,the Trustee generally does not have any direct contact with working interestowners, other than employees of the managing general partner, and relies on themanaging general partner of the Partnership to request and obtain informationdeemed material to the Trust by the Trustee.

·  Under the terms of the Trust Agreement, theTrustee is entitled to rely on certain experts in good faith. While the Trusteehas no reason to believe its reliance upon experts is unreasonable, itsreliance on experts and limited access to information may be viewed as aweakness.

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

*Changesin Internal Control Over Financial Reporting.**  *There has been no change in theTrustee’s internal control over financial reporting during the three monthsended September 30, 2004 that has materially affected, or is reasonablylikely to materially affect, the Trustee’s internal control over financial reporting.The Trustee notes for purposes of clarification that it has no authority over,and makes no statement concerning, the internal control over financialreporting of the working interest owners or the managing general partner of thePartnership.

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**PART II****—****OTHER INFORMATION**

***Item 6.*Exhibits**

****

(Asteriskindicates exhibit previously filed with the Securities and Exchange Commissionand incorporated herein by reference. JPMorgan Chase Bank was formerly known asThe Chase Manhattan Bank and is the successor by mergers to the original nameof 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**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned,thereunto duly authorized.
|        | MESA OFFSHORE TRUST |
|--------|---------------------|
|   | By:                 | /s/ JPMORGAN CHASE BANK, Trustee |
|   | By:                 |  |
|   | *** ***        | **Mike  Ulrich*Vice President & Trust Officer*** |

 

Date: November 14, 2004

The Registrant, Mesa Offshore Trust, has no principalexecutive officer, principal financial officer, board of directors or personsperforming similar functions. Accordingly, no additional signatures areavailable and none have been provided.

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