**SECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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FORM 10-Q
| **x** | **QUARTERLY REPORT PURSUANT TO SECTION 13 OR  15() OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED  JUNE 30, 2004**           |
|-------|----------------------------------------------------------------------------------------------------------------------------------------------------------|
| **o** | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15() OF THE SECURITIES 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) has been subject to such filing requirementsfor 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 the Act). 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 August 11, 2004—71,980,216 Units of Beneficial Interest in MesaOffshore Trust.

 

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**PART I—FINANCIAL INFORMATION**

**Item 1. *Financial Statements.***

**MESAOFFSHORE TRUST**

**STATEMENTS OFDISTRIBUTABLE INCOME(Unaudited)**
| ** **                          | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|-------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                          | ** ** | **2004**                                        | ** ** | **2003**                                      | ** ** | **2004** | ** ** | **2003** | ** ** |
| Royalty income                      |       | $                                               | —     |                                          | $          | — |   | $ | — |   | $ | — |   |
| Interest income                     |       | 986                                             |       | 2,727                                         |       | 2,624 |   | 5,825 |   |
| General and  administrative expense |       | (986                                            | )          | (2,727                                        | )          | (2,624 | ) | (5,825 | ) |
| Distributable income                |       | $                                               | —     |                                          | $          | — |   | $ | — |   | $ | — |   |
| Distributable  income per unit      |       | $                                               | —     |                                          | $          | — |   | $ | — |   | $ | — |   |

 

**STATEMENTSOF ASSETS, LIABILITIES AND TRUST CORPUS**
| ** **                                                                         | ** ** | **June 30,  2004** | ** ** | **December 31,  2003** | ** ** |
|------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| ** **                                                                         | ** ** | **(Unaudited)**         | ** ** | ** **                  | ** ** |
| ASSETS                                                                             |       |                    |       |                        |       |
| Cash and short-term  investments                                                   |       | $                       | 576,236    |                        | $          | 938,827 |   |
| Interest  receivable                                                               |       | 331                     |       | 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                                                                       |       | $                       | 587,694    |                        | $          | 951,557 |   |
| LIABILITIES AND TRUST CORPUS                                                       |       |                    |       |                        |       |
| Reserve for Trust  expenses                                                        |       | $                       | 576,567    |                        | $          | 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                                                |       | $                       | 587,694    |                        | $          | 951,557 |   |

 

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

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**MESAOFFSHORE TRUST**

**STATEMENTS OFCHANGES IN TRUST CORPUS(Unaudited)**
| ** **                                      | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 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 notesare an integral part of these financial statements.)

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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 Trust properties nearing the end oftheir estimated productive lives, Royalty income received by the Trust in 2002and 2003 fell below the Termination Threshold prescribed by the TrustIndenture. In addition, there is an accumulated deficit due PNR as of June 30,2004 of $433,908 that will be deducted from any future gross proceeds on theRoyalty Properties, which deduction will reduce future Royalty income.

The December 31, 2003 reserve report prepared forthe Partnership indicates that Royalty income expected to be received by theTrust in 2004 will be below the Termination Threshold. The TerminationThreshold for 2003 was approximately $1.2 million. The reserve reportestimates that future Royalty income to the Trust will be zero for 2004 asestimated net proceeds from the Trust properties during 2004 will not besufficient to recoup the accumulated deficit existing at December 31,2003. In addition, the reserve report estimates that future Royalty income tothe Trust after 2004 will be approximately $2.2 million (net of therecoupment of the Trust deficit). Future Royalty income in the reserve reportwas calculated using oil and natural gas spot prices in effect at December 31,2003 of $31.42 per barrel and $5.97 per Mcf, respectively. Based on the currentestimates of future Royalty income and 2004 operational updates received fromPNR, the Trustee expects that Royalty income received by the Trust will fallbelow the Termination Threshold in 2004. **Accordingly,the Trustee anticipates that the Trust will be required to terminate under theprovisions of the Trust Indenture effective December 31, 2004.**

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PNR advised the Trust that it farmed out the Trust’sinterest in Brazos A-7 and A-39 so that two exploratory prospects could bedrilled during 2003 with the Trust retaining an overriding royalty interest.The first exploration prospect was drilled on Brazos A-7 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 announcedas a discovery. PNR has approved a plan to set minimal facilities, complete thewell and perform a production test prior to determining whether or not todevelop the project as a subsea tie-back into an existing platform. Equipmenthas been ordered and the production test should take place in late 2004. If thediscovery is deemed to be commercially viable, first sales will not take placeuntil early 2005, which is subsequent to the expected termination of the Trust.In addition, PNR advised the Trust that Stone Energy Corporation (“Stone”)recently completed an exploratory well that was placed on production early inthe third quarter of 2004. Even with this discovery, it is currently expectedthat any Royalty income generated from this prospect will not be received intime to eliminate the deficit balance and increase Royalty income above theThreshold Amount before the Trust terminates under the Indenture.

There are numerousuncertainties inherent in estimating and projecting the quantity and value ofproved reserves for the Trust properties, as many of the Trust properties arenearing the end of their productive lives and are therefore subject tounforeseen changes in production rates. As such, the foregoing statementsreflect only current reasonable expectations.

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 or provisionfor all liabilities of the Trust, and the Trust would be terminated.

**Note 2—Basis of Presentation**

The accompanying unaudited financial information hasbeen prepared by JPMorgan Chase Bank (the “Trustee”) in accordance with theinstructions to Form 10-Q. JPMorgan Chase Bank was formerly known 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.

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

(a)   Royalty incomerecorded for a month is the Trust’s interest in the amount computed and paid bythe working interest owner to the Partnership for such month rather than eitherthe value of a portion of the oil and gas produced by the working interestowner for such month or the amount subsequently determined to be 90% of the netproceeds for such month;

(b)   Interest income,interest receivable and distributions payable to unitholders include interestto be earned on short-term investments from the financial statement datethrough the next date of distribution;

(c)   Trust generaland administrative expenses, net of reimbursements, are recorded in the monththey accrue;

(d)   Amortization ofthe net overriding royalty interest, which is calculated on the basis ofcurrent royalty income in relation to estimated future royalty income, ischarged directly to trust corpus since such amount does not affectdistributable income; and

(e)   Distributionspayable are determined on a monthly basis and are payable to unitholders ofrecord as of the last business day of each month or such other day as theTrustee determines is required to comply with legal or stock exchangerequirements. However, cash distributions are made quarterly in January, April,July and October, and include interest earned from the monthly recorddates 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 six months ending June 30,2004, proceeds from oil and gas sales exceeded operating and capital costsincurred; however, no Royalty income was reported as the net proceeds were usedto reduce the accumulated deficit. For the three months ended June 30, 2004,the deficit was reduced by $110,111 ($110,100 net to the Trust). There remainsan accumulated deficit balance due PNR as of June 30, 2004 of $433,908that will be deducted from any future gross proceeds on the Royalty Properties,which deduction will reduce future Royalty income. In addition, no Royaltyincome will be distributed to unitholders until the Trustee recoups Trustexpenses being paid from the reserve that the Trustee has established foranticipated future expenses. As of June 30, 2004, the Reserve for Trustexpenses is $576,567 and $1,423,433 is expected to be recouped by the Trusteefrom future Royalty income 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 June 30, 2004 was $2,682,594.

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**Item 2. *Management’s Discussionand 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, includingunder the section “Business—Principal Trust Risk Factors.” All subsequentwritten and oral forward-looking statements attributable to the Trust orpersons acting on its behalf are expressly qualified in their entirety by theCautionary 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 six months ended June 30, 2004 and 2003:
| ** **                                         | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|----------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                         | ** ** | **2004**                                        | ** ** | **2003**                                      | ** ** | **2004** | ** ** | **2003** | ** ** |
| Gross proceeds @  90%                              |       | $                                               | 143,300    |                                          | $          | 299,883 |   | $ | 384,241 |   | $ | 430,129 |   |
| Operating  expenditures @ 90%                      |       | (33,189                                         | )          | (169,185                                      | )          | (121,411 | ) | (398,094 | ) |
| Capital  expenditures @ 90%                        |       | —                                          |       | (2,359                                        | )          | — |   | (10,409 | ) |
| Net proceeds  (deficit)                            |       | 110,111                                         |       | 128,339                                       |       | 262,830 |   | 21,626 |   |
| Increase  (decrease) in deficit due PNR            |       | (110,111                                        | )          | (128,339                                      | )          | (262,830 | ) | (21,626 | ) |
| Net proceeds  after deficit recovery               |       | —                                          |       | —                                        |       | — |   | — |   |
| Royalty Income (99.99%)                            |       | $                                               | —     |                                          | $          | — |   | $ | — |   | $ | — |   |
| Accumulated deficit due  PNR (as of end of period) |       | $                                               | (433,908   | )                                             | $          | (803,992 | ) | $ | (433,908 | ) | $ | (803,992 | ) |

 

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Belowis a summary of distributable income for the three and six months ended June 30,2004 and 2003:
| ** **                               | ** ** | **Three Months Ended  June 30,** | ** **  | **Six Months Ended  June 30,** | ** ** |
|------------------------------------------|------------|-------------------------------------------------|-------------|-----------------------------------------------|------------|
| ** **                               | ** ** | **2004**                                        | ** **  | **2003**                                      | ** ** | **2004** | ** ** | **2003** | ** ** |
| Royalty Income                           |       | $                                               | —      |                                          | $          | — |   | $ | — |   | $ | — |   |
| Interest income                          |       | 986                                             |        | 2,727                                         |       | 2,624 |   | 5,825 |   |
| General and  administrative expenses     |       | (986                                            | )           | (2,727                                        | )          | (2,624 | ) | (4,825 | ) |
| Distributable  income                    |       | $                                               | —      |                                          | $          | — |   | $ | — |   | $ | — |   |
| Distributable  income per unit           |       | $                                               | —      |                                          | $          | — |   | $ | — |   | $ | — |   |
| Recoupment of reserve for Trust expenses |       | $                                               | (1,423,433) |                                          | $          | (1,203,937) |   | $ | (1,423,433) |   | $ | (1,203,937) |   |

 

The Trust had nodistributable income for the three and six months ended June 30, 2004 and2003. Since December 2001, the Trust has been in a deficit position to PNRas a result of significant decline in production on properties in which theTrust has a royalty interest. The Trust continues to be in a deficit positionas a result of lower production on all properties due to these propertiesnearing the end of their productive lives. See “—Operational Review” below.

**OperationalReview**

PNR has advised the Trust that during the secondquarter of 2004 its offshore gas production was marketed under short-termcontracts at spot market prices primarily to Occidental Petroleum Corp. and 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 thesecond quarter of 2004 were generally higher than spot market prices in thesecond quarter of 2003.

The amount of cash distributed by the Trust isdependent on, among other things, the sales prices and quantities of gas, crudeoil and condensate produced from the Royalty Properties and the quantitiessold. Substantial uncertainties exist with regard to future gas and oil prices,which are subject to fluctuations due to the regional supply and demand fornatural gas and oil, production levels and other activities of the Organizationof the Petroleum Exporting Countries (“OPEC”) and other oil and gas producers,weather, storage levels, industrial growth, conservation measures, competitionand other variables.

Below is an operationalreview of the remaining producing Trust properties:

***BrazosA-7 and A-39***
| ** **                    | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|-------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                    | ** ** | **2004**                                        | ** ** | **2003**                                      | ** ** | **2004** | ** ** | **2003** | ** ** |
| Gross proceeds @  90% .       |       | $                                               | 8,928      |                                          | $          | 100,754 |   | $ | 99,452 |   | $ | 206,602 |   |
| Operating  expenditures @ 90% |       | (32,444                                         | )          | (113,600                                      | )          | (122,044 | ) | (222,634 | ) |
| Capital  expenditures @ 90%   |       | —                                          |       | (385                                          | )          |   |   | 2,482 |   |
| Net proceeds (deficit)        |       | $                                               | (23,516    | )                                             | $          | (13,231 | ) | $ | (22,592 | ) | $ | (13,550 | ) |
| Producing wells               |       | 1                                               |       | 2                                             |       | 1 |   | 2 |   |

 

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The Brazos A-7 and A-39blocks continued to experience a decrease in natural gas production due tonatural production decline. As of June 30, 2004, these two blocks had onewell producing, the Brazos A-7 No. B-1 well. The Brazos A-39 No. A-3well ceased production during the fourth quarter of 2003. PNR farmed out theTrust’s interest in both of these blocks so that two exploration prospectscould be drilled and in which the Trust will retain 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 which has been announcedas a discovery. PNR has approved a plan to set minimal facilities, complete thewell and perform a production test prior to determining whether or not todevelop the project as a subsea tie-back into an existing platform. Equipmenthas been ordered and the production test should take place in late 2004. If thediscovery is deemed to be commercially viable, first sales will not take placeuntil early 2005, which is subsequent to the expected termination of the Trust.

***West Delta 61 and 62***
| ** **                    | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|-------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                    | ** ** | **2004**                                        | ** ** | **2003**                                      | ** ** | **2004** | ** ** | **2003** | ** ** |
| Gross proceeds @  90%         |       | $                                               | 134,372    |                                          | $          | 199,129 |   | $ | 284,789 |   | $ | 223,527 |   |
| Operating  expenditures @ 90% |       | (745                                            | )          | (55,585                                       | )          | 633 |   | (175,460 | ) |
| Capital  expenditures @ 90%   |       | —                                          |       | (1,974                                        | )          | — |   | (12,891 | ) |
| Net proceeds (deficit)        |       | $                                               | 133,627    |                                          | $          | 141,570 |   | $ | 285,422 |   | $ | 35,176 |   |
| Producing wells               |       | 3                                               |       | 3                                             |       | 3 |   | 3 |   |

 

The West Delta 61 and 62blocks experienced a decrease in oil and natural gas production in the secondquarter 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 byyear-end with the facilities being completely abandoned during 2003. The onlyremaining wells on this block are in West Delta 61. PNR farmed out a portion ofWest Delta 61 to Stone retaining a 12.5% (11.25% net to the Trust) overridingroyalty interest. Stone recently completed drilling an exploratory well thatwas placed on production early in the third quarter of 2004. Even with thisdiscovery, it is currently expected that any Royalty income generated from thisprospect will not be received in time to eliminate the deficit balance andincrease Royalty income above the Threshold Amount before the Trust terminatesunder the Indenture.

***CapitalExpenditures***

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

***AbandonmentExpenditures***

The table belowprovides a rollforward of the abandonment and removal costs cash reserve thatPNR has withheld from the Trust:
| Balance,  December 31, 2003          |   | $        | 2,800,643 |   |
|-------------------------------------------|--------|----------|-----------|--------|
| Abandonment cost  incurred (WD 61 and 62) |   | (118,049 | )         |
| Balance,  June 30, 2004              |   | $        | 2,682,594 |   |

 

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The following tables provide a summary of thecalculations of the net proceeds attributable to the Partnership’s royaltyinterest (unaudited):
| ** **                                            | ** ** | **Brazos A-7  and A-39** | ** ** | **West Delta  61 and 62** | ** ** | **Total** | ** ** |   |
|-------------------------------------------------------|------------|------------------------------------|------------|------------------------------------------|------------|-----------|------------|--------|
| **Three Months Ended June 30, 2004:**            |       |                               |       |                                     |       |      |       |
| Ninety percent of gross  proceeds                     |       | $                                  | 8,928      |                                     | $          | 134,372   |       | $      | 143,300 |   |
| Less ninety percent of—                          |       |                               |       |                                     |       |      |       |
| Operating  expenditures                               |       | (32,444                            | )          | (745                                     | )          | (33,189   | )          |
| Capital costs  recovered                              |       | —                             |       | —                                   |       | —    |       |
| Net proceeds  (deficit)                               |       | $                                  | (23,516    | )                                        | $          | 133,627   |       | $      | 110,111 |   |
| Trust share of net  proceeds (99.99%)                 |       |                               |       |                                     |       | $         | 110,100    |   |
| Recoupment of  deficit                                |       |                               |       |                                     |       | (110,100  | )          |
| Royalty income                                        |       |                               |       |                                     |       | —    |       |
| Trust Deficit                                         |       |                               |       |                                     |       | $         | 433,908    |   |
| Production Volumes and Average Prices:                |       |                               |       |                                     |       |      |       |
| Crude oil,  condensate and natural gas liquids (Bbls) |       | 22                                 |       | 2,437                                    |       | 2,459     |       |
| Average sales  price per Bbl                          |       | $                                  | 30.36      |                                     | $          | 32.52     |       | $      | 32.50 |   |
| Natural gas (Mcf)                                     |       | 492                                |       | 10,159                                   |       | 10,651    |       |
| Average sales  price per Mcf                          |       | $                                  | 5.08       |                                     | $          | 5.42      |       | $      | 5.95 |   |
| Producing wells                                       |       | 1                                  |       | 3                                        |       | 4         |       |
| **Three Months Ended  June 30, 2003:**           |       |                               |       |                                     |       |      |       |
| Ninety percent of  gross proceeds                     |       | $                                  | 100,754    |                                     | $          | 199,129   |       | $      | 299,883 |   |
| Less ninety percent of—                          |       |                               |       |                                     |       |      |       |
| Operating  expenditures                               |       | (113,600                           | )          | (55,585                                  | )          | (169,185  | )          |
| Capital costs  recovered                              |       | (385                               | )          | (1,974                                   | )          | (2,359    | )          |
| Net proceeds  (deficit)                               |       | $                                  | (13,231    | )                                        | $          | 141,570   |       | $      | 128,339 |   |
| Trust share of net  proceeds (99.99%)                 |       |                               |       |                                     |       | $         | 128,326    |   |
| Increase in  deficit                                  |       |                               |       |                                     |       | (128,326  | )          |
| Royalty income                                        |       |                               |       |                                     |       | —    |       |
| Trust Deficit                                         |       |                               |       |                                     |       | $         | 803,992    |   |
| Production Volumes and  Average Prices:               |       |                               |       |                                     |       |      |       |
| Crude oil,  condensate and natural gas liquids (Bbls) |       | 48                                 |       | 2,057                                    |       | 2,105     |       |
| Average sales  price per Bbl                          |       | $                                  | 29.15      |                                     | $          | 23.74     |       | $      | 23.86 |   |
| Natural gas (Mcf)                                     |       | 27,243                             |       | 21,984                                   |       | 49,227    |       |
| Average sales  price per Mcf                          |       | $                                  | 3.65       |                                     | $          | 6.83      |       | $      | 5.07 |   |
| Producing wells                                       |       | 2                                  |       | 3                                        |       | 5         |       |
|                                                       |            |                                    |            |                                          |            |           |            |        |  |  |  |  |  |

 

The amounts shown are for Mesa Offshore RoyaltyPartnership. Producing wells indicate the number of wells capable of productionas of the end of the period. The amounts for the three months ended June 30,2004 and 2003 represent actual production for the periods February 2004 throughApril 2004 and February 2003 through April 2003, respectively.Capital costs recovered represents capital costs incurred during the current orprior periods to the extent that such costs have been recovered by PNR fromcurrent period Gross Proceeds. The unexpended amount withheld by PNR for futureabandonment costs at June 30, 2004 was $2,682,594. The Trust deficitbalance due PNR of $433,908 as of June 30, 2004 will be deducted from anyfuture gross proceeds on the Royalty properties, which deduction will reducefuture Royalty income. As of June 30, 2004, $1,423,433 will be recouped bythe Trustee from Royalty income before Trust distributions will resume.

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| ** **                                           | ** ** | **Brazos A-7  and A-39** | ** ** | **West Delta  61 and 62** | ** ** | **Total** | ** ** |
|------------------------------------------------------|------------|------------------------------------|------------|------------------------------------------|------------|-----------|------------|
| **Six Months Ended June 30,  2004:**            |       |                               |       |                                     |       |      |       |
| Ninety percent of gross proceeds                     |       | $                                  | 99,452     |                                     | $          | 284,789   |       | $ | 384,241 |   |
| Less ninety percent of—                         |       |                               |       |                                     |       |      |       |
| Operating expenditures                               |       | (122,044                           | )          | 633                                      |       | (121,411  | )          |
| Capital costs recovered                              |       | —                             |       | —                                   |       | —    |       |
| Net proceeds (deficit)                               |       | $                                  | (22,592    | )                                        | $          | 285,422   |       | $ | 262,830 |   |
| Trust share of net proceeds (99.99%)                 |       |                               |       |                                     |       | $         | 262,804    |   |
| Recoupment of deficit                                |       |                               |       |                                     |       | (262,804  | )          |
| Royalty income                                       |       |                               |       |                                     |       | —    |       |
| Trust Deficit                                        |       |                               |       |                                     |       | $         | 433,908    |   |
| Production  Volumes and Average Prices:              |       |                               |       |                                     |       |      |       |
| Crude oil, condensate and natural gas liquids (Bbls) |       | 22                                 |       | 5,944                                    |       | 5,966     |       |
| Average sales price per Bbl                          |       | $                                  | 34.69      |                                     | $          | 29.80     |       | $ | 29.81 |   |
| Natural gas (Mcf)                                    |       | 18,787                             |       | 21,611                                   |       | 40,398    |       |
| Average sales price per Mcf                          |       | $                                  | 5.26       |                                     | $          | 4.98      |       | $ | 5.11 |   |
| Producing wells                                      |       | 1                                  |       | 3                                        |       | 4         |       |
| **Six  Months Ended June 30, 2003:**            |       |                               |       |                                     |       |      |       |
| Ninety percent of gross proceeds                     |       | $                                  | 206,602    |                                     | $          | 223,527   |       | $ | 430,129 |   |
| Less  ninety percent of—                        |       |                               |       |                                     |       |      |       |
| Operating expenditures                               |       | (222,634                           | )          | (175,460                                 | )          | (398,094  | )          |
| Capital costs recovered                              |       | 2,482                              |       | (12,891                                  | )          | (10,409   | )          |
| Net proceeds (deficit)                               |       | $                                  | (13,550    | )                                        | $          | 35,176    |       | $ | 21,626 |   |
| Trust share of net proceeds (99.99%)                 |       |                               |       |                                     |       | $         | 21,624     |   |
| Increase in deficit                                  |       |                               |       |                                     |       | (21,624   | )          |
| Royalty income                                       |       |                               |       |                                     |       | —    |       |
| Trust Deficit                                        |       |                               |       |                                     |       | $         | 803,992    |   |
| Production  Volumes and Average Prices:              |       |                               |       |                                     |       |      |       |
| Crude oil, condensate and natural gas liquids (Bbls) |       | 123                                |       | 2,660                                    |       | 2,783     |       |
| Average sales price per Bbl                          |       | $                                  | 26.83      |                                     | $          | 24.86     |       | $ | 24.95 |   |
| Natural gas (Mcf)                                    |       | 53,084                             |       | 23,721                                   |       | 76,805    |       |
| Average sales price per Mcf                          |       | $                                  | 3.83       |                                     | $          | 6.63      |       | $ | 4.70 |   |
| Producing wells                                      |       | 2                                  |       | 3                                        |       | 5         |       |

 

The amounts shown are for Mesa Offshore RoyaltyPartnership. Producing wells indicate the number of wells capable of productionas of the end of the period. The amounts for the six months ended June 30,2004 and 2003 represent actual production for the periods November 2003through April 2004 and November 2002 through April 2003,respectively. Capital costs recovered represents capital costs incurred duringthe current or prior periods to the extent that such costs have been recoveredby PNR from current period Gross Proceeds. The unexpended amount withheld byPNR for future abandonment costs at June 30, 2004 was $2,682,594. TheTrust deficit balance due PNR of $433,908 as of June 30, 2004 will bededucted from any future gross proceeds on the Royalty properties, which deductionwill reduce future Royalty income. As of June 30, 2004, $1,423,433 will berecouped by the Trustee from Royalty income before trust distributions willresume.

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***Production and Price Review***

Production volumes for natural gas decreased to 10,651Mcf in the second quarter of 2004 as compared with 49,227 Mcf in the secondquarter of 2003. The average sales price received for natural gas in the secondquarter of 2004 was $5.95 per Mcf as compared with $5.07 per Mcf in the secondquarter of 2003. Crude oil, condensate and natural gas liquids productionvolumes increased to 2,459 barrels in the second quarter of 2004 as compared to2,105 barrels in the second quarter of 2003. The average sales price in thesecond quarter of 2004 for crude oil, condensate and natural gas liquids was $32.50per barrel as compared with $23.86 per barrel in the second quarter of 2003.

Productionvolumes for natural gas decreased to 40,398 Mcf for the six months ended June 30,  2004 as compared with 76,805 Mcf for the sixmonths ended June 30, 2003. The average sales price received for naturalgas for the six months ended June 30, 2004 was $5.11 per Mcf as comparedwith $4.70 per Mcf for the six months ended June 30, 2003. Crude oil,condensate and natural gas liquids production volumes increased to 5,966barrels for the six months ended June 30, 2004 as compared to 2,783barrels for the six months ended June 30, 2003. The average sales pricefor the six months ended June 30, 2004 for crude oil, condensate andnatural gas liquids was $29.81 per barrel as compared with $24.95 per barrelfor the six months ended June 30, 2003.

**Termination of the Trust**

The terms of the Mesa Offshore Trust Indentureprovide, among other things, that the Trust will terminate upon the first tooccur of the following events: (1) the total amount of cash received peryear by the Trust for each of three successive years commencing after December 31,1987 is less than ten times one-third of the total amount payable to theTrustee as compensation for such three-year period (the “TerminationThreshold”) or (2) a vote by holders of a majority of the outstandingunits in favor of termination. Because the Trust will terminate in the eventthe total amount of cash received per year by the Trust falls below certainlevels, it would be possible for the Trust to terminate even though some of theRoyalty Properties continued to have remaining productive lives. Forinformation regarding the estimated remaining life of each of the RoyaltyProperties and the estimated future net revenues of the Trust based oninformation provided by PNR, see the Trust’s 2003 Annual Report on Form 10-K.Upon termination of the Trust, the Trustee will sell for cash all the assetsheld in the Trust estate and make a final distribution to unitholders of anyfunds remaining after all Trust liabilities have been satisfied. The discussionset forth above is qualified in its entirety by reference to the TrustIndenture itself, which is an exhibit to the Trust’s 2003 Annual Report on Form 10-Kand is available upon request from the Trustee.

The December 31, 2003 reserve report prepared forthe Partnership indicates that Royalty income expected to be received by theTrust in 2004 will be below the Termination Threshold. The TerminationThreshold for 2003 was approximately $1.2 million. The reserve reportestimates that future Royalty income to the Trust will be zero for 2004 asestimated net proceeds from the Trust properties during 2004 will not besufficient to recoup the accumulated deficit existing at December 31,2003. In addition, the reserve report estimates that future royalty income tothe Trust after 2004 will be approximately $2.2 million (net of therecoupment of the Trust deficit). Future Royalty income in the reserve reportwas calculated using oil and natural gas spot prices in effect at December 31,2003 of $31.42 per barrel and $5.97 per Mcf, respectively. Based on the currentestimates of future Royalty income and 2004 operational updates received fromPNR, the Trustee expects that Royalty income received by the Trust will fallbelow 

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the Termination Thresholdin 2004. **Accordingly, the Trustee anticipatesthat the Trust will be required to terminate under the provisions of the TrustIndenture effective December 31, 2004.**

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 is subsequent to theexpected termination of the Trust. In addition, PNR advised the Trust thatStone recently completed an exploratory well that was placed on production earlyin the third quarter 2004. Even with this discovery, it is currently expectedthat any Royalty income generated from this prospect will not be received intime to eliminate the deficit balance and increase Royalty income above theThreshold Amount before the Trust terminates under the Indenture.

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.

***Item 3. *Quantitativeand Qualitative Disclosures About Market Risk.**

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

***Item 4.****** ***Controls andProcedures.

*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.

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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 that thesecontrols and procedures are effective, while noting certain limitations ondisclosure 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 in disclosurecontrols and procedures may be deemed to include:

·                    Theworking interest owners alone control (i) historical operating data,including production volumes, marketing of products, operating and capitalexpenditures, environmental and other liabilities, the effects of regulatorychanges and the number of producing wells and acreage, (ii) plans forfuture operating and capital expenditures, (iii) geological data relatingto reserves, as well as the reserve report that contains projected production,operating expenses and capital expenses, and (iv) information relating toprojected production. The Trustee does not control this information and reliesentirely on the working interest owners to provide accurate and timelyinformation when requested for use in the Trust’s periodic reports.

·                    TheTrustee relies on information provided by the managing general partner of thePartnership that is collected by the managing general partner from the workinginterest owners. While the Trustee may request information through the managinggeneral partner, the Conveyance together with the Partnership Agreement givesonly the managing general partner of the Partnership, as the Royalty Owner, theactual authority and discretion to request and receive financial information regardingthe Royalty Properties from the working interest owners. While the Trusteerequests material information for use in periodic reports as part of itsdisclosure controls and procedures, the Trustee generally does not have anydirect contact with working interest owners, other than employees of themanaging general partner, and relies on the managing general partner of thePartnership to request and obtain information deemed material to the Trust bythe Trustee.

·                    Underthe terms of the Trust Agreement, the Trustee is entitled to rely on certainexperts in good faith. While the Trustee has no reason to believe its relianceupon experts is unreasonable, its reliance on experts and limited access toinformation may be viewed as a weakness.

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

*Changes in InternalControl Over Financial Reporting.**  *There has been no change in theTrustee’s internal control over financial reporting during the three monthsended June 30, 2004 that has materially affected, or is reasonably likelyto 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**

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

**(a)**         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                                                                                                                                                                                                                         |       |                                  |       |                |

 

**(b)**         Reportson Form 8-K

Current reports on Form 8-K were filed withthe Securities and Exchange Commission on April 20, 2004, May 21,2004 and June 18, 2004.

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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:                 | /s/ Mike  Ulrich |
|   |                | **Mike Ulrich**

***Vice President & Trust Officer*** |

 

Date: August 11, 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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