**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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FORM 10-K

**(Mark One)**

**x**                              ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDEDDECEMBER 31, 2004

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

 

**Registrant’s telephone number,including area code:**1-800-852-1422

Securities registeredpursuant to Section 12(b) of the Act:

|      | **Title of Each Class** | ** ** | ** ** | ** ** | **Name of Each Exchange On Which Registered** | ** ** | ** ** |
|------|----------------------------------------|------------|------------|------------|-----------------------------------------------------------------------------|------------|------------|
| None |                                   | None       |       |

 

Securities registered pursuant to Section 12(g) ofthe Act:

**Units of beneficialinterest**

(Title of Class)

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) ofthe Securities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the registrant was required to file such reports), and(2) has been subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K isnot contained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check markwhether the registrant is an accelerated filer (as defined in Rule 12b-2of the Act). Yes o  No x

The aggregate market valueof 71,980,216 Units of Beneficial Interest in Mesa Offshore Trust held bynon-affiliates of the registrant at the closing sales price on June 30,2004, of $0.03 was approximately $2,159,000.

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

As of March 30, 2005,71,980,216 Units of Beneficial Interest were outstanding in Mesa OffshoreTrust.

DOCUMENTSINCORPORATED BY REFERENCE: **None.**

 

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**TABLEOF CONTENTS**
|                   | ** ** | ** **                                                                                  | ** ** | **Page** | ** ** |
|-------------------|------------|---------------------------------------------------------------------------------------------|------------|----------|------------|
| **PART I**   |
| Item 1.           |       | Business                                                                                    | 4          |     |
|              |       | Description of the Trust                                                                    | 4          |     |
|              |       | Description of the Units                                                                    | 6          |     |
|              |       | Termination of the Trust                                                                    | 8          |     |
|              |       | Description of Royalty Properties                                                           | 9          |     |
|              |       | Contracts                                                                                   | 16         |     |
|              |       | Regulation and Prices                                                                       | 17         |     |
|              |       | Principal Trust Risk Factors                                                                | 19         |     |
| Item 2.           |       | Properties                                                                                  | 22         |     |
| Item 3.           |       | Legal Proceedings                                                                           | 22         |     |
| Item 4.           |       | Submission of Matters to a Vote of  Security Holders                                        | 22         |     |
| **PART II**  |
| Item 5.           |       | Market for the Registrant’s Common  Equity and Related Unitholder Matters              | 23         |     |
| Item 6.           |       | Selected Financial Data                                                                     | 23         |     |
| Item 7.           |       | Management’s Discussion and  Analysis of Financial Condition and Results of Operations | 24         |     |
|              |       | Net Proceeds, Production and  Average Prices (Unaudited)                                    | 29         |     |
| Item 7A.          |       | Quantitative and Qualitative  Disclosures About Market Risk                                 | 30         |     |
| Item 8.           |       | Financial Statements and  Supplementary Data                                                | 31         |     |
| Item 9.           |       | Changes in and Disagreements with  Accountants on Accounting and Financial Disclosure       | 39         |     |
| Item 9A.          |       | Controls and Procedures                                                                     | 39         |     |
| **PART III** |
| Item 10.          |       | Directors and Executive Officers  of the Registrant                                         | 41         |     |
| Item 11.          |       | Executive Compensation                                                                      | 41         |     |
| Item 12.          |       | Security Ownership of Certain  Beneficial Owners and Management                             | 41         |     |
| Item 13.          |       | Certain Relationships and Related  Transactions                                             | 41         |     |
| Item 14.          |       | Principal Accountant Fees and  Services                                                     | 42         |     |
| **PART IV**  |
| Item 15.          |       | Exhibits, Financial Statement  Schedules and Reports                                        | 43         |     |
| SIGNATURES        | 44         |                                                                                        |
|                   |            |                                                                                             |            |          |            |  |

 

 

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**Note RegardingForward-Looking Statements**

This Form 10-K includes “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934,as amended. All statements other than statements of historical facts includedin this Form 10-K, including without limitation the statements under“Business—Termination of the Trust,” “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations” and Note 1 to the financialstatements of the Trust regarding the future net revenues of the Trust, areforward-looking statements. Although Pioneer Natural Resources Company (“Pioneer”)has advised the Trust that it believes that the expectations reflected in suchforward-looking statements are reasonable, no assurance can be given thatsuch expectations will prove to have been correct. Important factors that couldcause actual results to differ materially from expectations (“CautionaryStatements”) are disclosed in this Form 10-K, including, withoutlimitation in conjunction with the forward-looking statements included inthis Form 10-K. A consolidated summary description of principal riskfactors that could cause actual results to differ is also set forth in this Form 10-Kunder “Business—Principal Trust Risk Factors.” All subsequent written and oralforward-looking statements attributable to the Trust or persons acting onits behalf are expressly qualified in their entirety by the CautionaryStatements.

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**PART I**

**Item 1.**                        Business.

**DESCRIPTION OF THETRUST**

The Mesa Offshore Trust (the “Trust”), created underthe laws of the State of Texas, maintains its offices at the office of theTrustee, JPMorgan Chase Bank, N.A. (the “Trustee”), 700 Lavaca, Austin, Texas 78701.The telephone number of the Trust is 1-800-852-1422. JPMorganChase Bank, N.A. was formerly known as The Chase Manhattan Bank and is thesuccessor by mergers to the original name of the Trustee, Texas Commerce BankNational Association.

The Trustee does not maintain a website for filings bythe Trust with the U.S. Securities and Exchange Commission (“SEC”). Electronicfilings by the Trust with the SEC are available free of charge through the SEC’swebsite at *www.sec.gov.*

The principal asset of the Trust consists of a 99.99%interest in the Mesa Offshore Royalty Partnership (the “Partnership”). TheTrust was created on December 28, 1982, effective December 1, 1982,when Mesa Petroleum Co. conveyed to the Partnership certain overriding royaltyinterests (collectively, the “Royalty”) carved out of Mesa Petroleum Co.’sexisting working interests in ten producing and non-producing oil and gasleases offshore Louisiana and Texas (the “Royalty Properties”). The Partnershipwas formed for the purpose of receiving and holding the Royalty, receiving theproceeds from the Royalty, paying the liabilities and expenses of thePartnership and disbursing remaining revenues to the Trustee and Mesa OffshoreManagement Co., the managing general partner of the Partnership at that time,in accordance with their interests. 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, formerly a wholly ownedsubsidiary of MESA Inc., and Parker & Parsley Petroleum Companymerged with and into Pioneer Natural Resources USA, Inc. (successor toMesa Operating Co.), 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 hereinafter used in this report, theterm PNR generally refers to the operator of the Royalty Properties, unlessotherwise indicated. See “Termination of the Trust” on page 8 of this Form 10-Kfor additional information regarding PNR and the Trust.

Units of beneficial interest (“units”) in the Trustwere issued on December 28, 1982 to Mesa Petroleum Co. shareholders, whoreceived one unit for each share of Mesa Petroleum Co. common stock held.

The terms of the Mesa Offshore Trust Indenture (the “TrustIndenture”) provide, among other things, that: (1) the Trust cannotacquire any asset other than its interest in the Partnership and cannot engagein any business or investment activity; (2) the Royalty can be sold inpart or in total for cash upon approval of the unitholders or upon terminationof the Trust; (3) the Trustee can establish cash reserves and borrow fundsto pay liabilities of the Trust and can pledge the assets of the Trust tosecure payment of the borrowing; (4) the Trustee will make quarterlydistributions of cash available for distribution to the unitholders in January,April, July and October of each year; and (5) the Trust willterminate upon the first to occur of the following events: (i) the totalamount of cash received per year by the Trust for each of three successiveyears commencing after December 31, 1987 is less than ten times one-thirdof the total amount payable to the Trustee as compensation for such three-yearperiod (the “Termination Threshold”) or (ii) a vote by holders of amajority of the outstanding units in favor of termination. Amounts paid to theTrustee as compensation were approximately $148,000, $152,000, and $84,000, forthe years 2004, 2003 and 2002, respectively. As described further in “Terminationof the Trust” on page 8 of this Form 10-K, the TerminationThreshold was met in each of the three consecutive years ending December 31,2004. Upon 

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termination of the Trust,the Trustee will sell for cash all the assets held in the Trust estate and makea final distribution to unitholders of any funds remaining after all Trust liabilitieshave been satisfied.

The terms of the First Amended and Restated Articlesof General Partnership of the Partnership (the “Partnership Agreement”) providethat the Partnership shall dissolve upon the occurrence of any of thefollowing: (1) December 31, 2030; (2) the election of theTrustee to dissolve the Partnership; (3) the termination of the Trust; (4) thebankruptcy of the Managing General Partner; or (5) 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.

Under the instrument conveying the Royalty to thePartnership (the “Conveyance”), the Trust is entitled to its share (99.99%) of90% of the Net Proceeds, as hereinafter defined, realized from the sale of thehydrocarbons as, if and when produced from the Royalty Properties. See “Descriptionof Royalty Properties” on page 6 of this Form 10-K. The Conveyanceprovides for a monthly computation of Net Proceeds. “Net Proceeds” means theexcess of Gross Proceeds, as hereinafter defined, received by PNR during aparticular period over operating and capital costs and an amount to berecovered for future abandonment costs during such period. “Gross Proceeds”means generally the amount received by PNR from the sale of its share ofminerals covered by the Royalty, subject to certain adjustments. Operatingcosts means, generally, costs incurred by PNR in operating the RoyaltyProperties, including capital costs. If operating and capital costs exceed theGross Proceeds for any month, the excess plus interest thereon at the primerate of the Bank of America plus one-half percent is recovered out of futureGross Proceeds prior to the making of further payment to the Trust. The Trustis not liable for any operating costs or other costs or liabilitiesattributable to the Royalty Properties or minerals produced therefrom. PNR, asowner of the working interest in the Royalty Properties, is required tomaintain books and records sufficient to determine the amounts payable underthe Royalty. Additionally, in the event of a controversy between PNR and anypurchaser as to the correct sale price for any production, amounts received byPNR and promptly deposited by it with an escrow agent are not considered ashaving been received by PNR and therefore are not subject to being payable withrespect to the Royalty until the controversy is resolved; but all amountsthereafter paid to PNR by the escrow agent will be considered amounts receivedfrom the sale of production. Similarly, operating costs include any amounts PNRis required to pay whether as a refund, interest or penalty to any purchaserbecause the amount initially received by PNR as the sales price was in excessof that permitted by the terms of any applicable contract, statute, regulation,order, decree or other obligation. Within 30 days following the close ofeach calendar quarter, PNR is required to deliver to the Trustee a statement ofthe computation of Net Proceeds attributable to such quarter.

The Royalty Properties are required to be operated byPNR in accordance with reasonable and prudent business judgment and good oiland gas field practices. PNR has the right to abandon any well or lease if, inits opinion, such well or lease ceases to produce or is not capable ofproducing oil, gas or other minerals in commercial quantities. PNR markets theproduction on terms deemed by it to be the best reasonably obtainable in thecircumstances. See “Contracts” on page 16 of this Form 10-K.The Trustee has no power or authority to exercise any control over theoperation of the Royalty Properties or the marketing of production therefrom.

The discussions of terms of the Trust Indenture, thePartnership Agreement and the Conveyance contained herein are qualified intheir entirety by reference to the Trust Indenture, the Partnership Agreementand the Conveyance themselves, which are exhibits to this Form 10-Kand are available upon request from the Trustee.

The Trust has no employees. Administrative functionsof the Trust are performed by the Trustee.

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**DESCRIPTION OF THE UNITS**

Each unit is evidenced bya transferable certificate issued by the Trustee. Each unit ranks equally as todistributions and has one vote on any matter submitted to unitholders. Eachunit evidences an undivided interest in the Trust, which in turn owns a 99.99%interest in the Partnership.

**Distributions**

The Trustee determines foreach month the amount of cash available for distribution for such month. Suchamount (the “Monthly Distribution Amount”) is equal to the excess, if any, of thecash distributed by the Partnership to the Trust during such month, plus anyother cash receipts of the Trust during such month (other than interest earnedon the Monthly Distribution Amount for any other month), over the liabilitiesof the Trust paid during such month, and adjusted for changes made by theTrustee during such month in any cash reserves established for the payment ofcontingent or future obligations of the Trust. The Monthly Distribution Amountfor each month is payable to unitholders of record on the monthly record date(the “Monthly Record Date”), which is the close of business on the lastbusiness day of such month, or such later date as the Trustee determines isrequired to comply with legal or stock exchange requirements. However, toreduce the administrative expenses of the Trust, the Trust Indenture providesthat the Trustee does not distribute cash monthly, but rather, during January,April, July and October of each year, distributes to each person whowas a unitholder of record on a Monthly Record Date during one or more of theimmediately preceding three months, the Monthly Distribution Amount for themonth or months that he was a unitholder of record, together with interestearned on such Monthly Distribution Amount from the Monthly Record Date to thepayment date.

**Liability ofUnitholders**

As regards to theunitholders, the Trustee is fully liable if the Trustee incurs any liabilitywithout ensuring that such liability will be satisfiable only out of the Trustassets (regardless of whether the assets are adequate to satisfy the liability)and in no event out of amounts distributed to, or other assets owned byunitholders. However, under Texas law, it is unclear whether a unitholder wouldbe jointly and severally liable for any liability of the Trust in the eventthat all of the following conditions were to occur: (1) the satisfactionof such liability was not by contract limited to the assets of the Trust; (2) theassets of the Trust were insufficient to discharge such liability; and (3) theassets of the Trustee were insufficient to discharge such liability. Althougheach unitholder should weigh this potential exposure in deciding whether toretain or transfer his units, the Trustee is of the opinion that because of thepassive nature of the Trust assets, the restrictions on the power of theTrustee to incur liabilities and the required financial net worth of anytrustee, the imposition of any liability on a unitholder is extremely unlikely.

**Federal Income TaxMatters**

This section is a summary of certain federal incometax matters of general application as of the date of this report. Except whereindicated, the discussion below describes general federal income taxconsiderations applicable to individuals who are citizens or residents of theUnited States. Accordingly, the following discussion has limited application todomestic corporations and persons subject to specialized federal income taxtreatment, such as regulated investment companies and insurance companies. Itis impractical to comment on all aspects of federal, state, local and foreignlaws that may affect the tax consequences of the transactions contemplatedhereby and of an investment in the units as they relate to the particularcircumstances of every unitholder. Federal income taxation is a highly complexmatter that may be affected by many considerations. **Each unitholder is encouraged to consult its own tax advisor with respectto its particular circumstances and the advisability of its ownership of units.**

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This summary is based oncurrent provisions of the Internal Revenue Code of 1986, as amended (the Code),existing and proposed Treasury Regulations thereunder and currentadministrative rulings and court decisions, all of which are subject to changesthat may or may not be retroactively applied. Some of the applicable provisionsof the Code have not been interpreted by the courts or the Internal RevenueService (the “IRS”). No assurance can be provided that the statements set forthherein (which do not bind the IRS or the courts) will not be challenged by theIRS or will be sustained by a court if so challenged.

*Ownership of Units*

The federal income taxconsequences to the unitholders of owning units depend on whether the Trust isclassifiable as a grantor trust, a non-grantor trust, or a corporation. TheTrustee reports on the basis that the Trust is a grantor trust. Based on itsrecent audit policy, the IRS is expected to concur with such action. No IRSruling has been received with respect to the Trust, however, and no court casehas been decided involving identical facts and circumstances. It is possible,therefore, that the IRS will assert on audit that the Trust is taxable as acorporation and that a court might agree with that assertion.

*Income andDepletion*

Royalty income, net of depletion and severance taxes,is portfolio income. Subject to certain exceptions and transitional rules,Royalty income cannot be offset by passive losses. Additionally, interestincome is portfolio income. Administrative expense is an investment expense.

Generally, prior to theRevenue Reconciliation Act of 1990, the transferee of an oil and gas propertycould not claim percentage depletion with respect to production from theproperty if it was “proved” at the time of the transfer. This rule is notapplicable in the case of transfers of properties after October 11, 1990.Thus, eligible unitholders who acquired units after that date are entitled toclaim an allowance for percentage depletion with respect to Royalty incomeattributable to these units to the extent that this allowance exceeds costdepletion as computed for the relevant period.

*Backup Withholding*

Distributions from theTrust are generally subject to backup withholding at a rate of 28% of thesedistributions. Backup withholding will not normally apply to distributions to aunitholder, however, unless the unitholder fails to properly provide to theTrust his taxpayer identification number or the IRS notifies the Trust that thetaxpayer identification number provided by the unitholder is incorrect.

*Sale of Units*

Generally, except forrecapture items, the sale, exchange or other disposition of a unit will resultin capital gain or loss measured by the difference between the tax basis in theunit and the amount realized. Effective for property placed in service after December 31,1986, the amount of gain, if any, realized upon the disposition of oil and gasproperty is treated as ordinary income up to the amount of intangible drillingand development costs incurred and depletion claimed to the extent it reducedthe taxpayer’s basis in the property. Under this provision, depletionattributable to a unit acquired after 1986 will be subject to recapture asordinary income upon disposition of the unit or upon disposition of the oil andgas property to which the depletion is attributable. The balance of any gain orany loss will be capital gain or loss if the unit was held by the unitholder asa capital asset, either long-term or short-term depending on the holding periodof the unit. This capital gain or loss will be long-term if a unitholder’sholding period exceeds one year at the time of sale or exchange. A long-termcapital gains rate of 15% applies to most capital assets sold or exchanged witha holding period of more than one year. Capital gain or loss will be short-termif the unit has not been held for more than one year at the time of sale orexchange.

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*Non-U.S.Unitholders*

In general, a unitholder who is a nonresident alienindividual or which is a foreign corporation, each a “non-U.S. unitholder” forpurposes of this discussion, will be subject to tax on the gross incomeproduced by the Royalty at a rate equal to 30% or, if applicable, at a lowertreaty rate. This tax will be withheld by the Trustee and remitted directly tothe United States Treasury. A non-U.S. unitholder may elect to treat the incomefrom the Royalty as effectively connected with the conduct of a United Statestrade or business under provisions of the Code or pursuant to any similarprovisions of applicable treaties. Upon making this election a unitholder isentitled to claim all deductions with respect to that income, but he mustfile a United States federal income tax return to claim these deductions.This election once made is irrevocable unless an applicable treaty allows theelection to be made annually.

The Code and the Treasury Regulations thereunder treatthe publicly traded Trust as if it were a United States real property holdingcorporation. Accordingly, non-U.S. unitholders may be subject to United Statesfederal income tax on the gain on the disposition of their units.

Federal income taxation ofa non-U.S. unitholder is a highly complex matter which may be affected by manyother considerations. Therefore, each non-U.S. unitholder is encouraged toconsult with its own tax adviser with respect to its ownership of units.

*Tax-ExemptOrganizations*

The Royalty and interestincome should not be unrelated business taxable income so long as, generally, aunitholder did not incur debt to acquire a unit or otherwise incur or maintaina debt that would not have been incurred or maintained if the unit had not beenacquired. Legislative proposals have been made from time to time which, ifadopted, would result in the treatment of Royalty income as unrelated businesstaxable income. Each tax-exempt unitholder should consult its own tax advisorwith respect to the treatment of royalty income.

**TERMINATION OF THE TRUST**

As discussed above under “Description of the Trust”,the terms of the Mesa Offshore Trust Indenture provide that the Trust willterminate when the total amount of cash received per year by the Trust for eachof three successive years commencing after December 31, 1987 is less thanthe Termination Threshold. **As a result ofcontinued declines in production on Royalty Properties nearing the end of theirestimated productive lives, Royalty income received by the Trust in 2002, 2003and 2004 fell below the Termination Threshold prescribed by the TrustIndenture, resulting in the contractual termination of the Trust effectiveafter December 31, 2004.**The Trustee, which has no authority ordiscretionary control over the timing of expenditures, production or income onthe Royalty Properties, has no discretion regarding the occurrence of theTermination Threshold or its consequences.

The Trust Indenture provides the Trustee a two-yearperiod during which it must sell all of the Trust properties. The TrustIndenture provides that such properties must be sold for cash and not for anyother consideration. The Trustee expects that the sale process will be open toany persons desiring to participate, but, as is customary, access toinformation and participation may be limited to persons who executeconfidentiality agreements regarding information provided by the workinginterest owners. The Trustee may also require bidders to identify themselvesclearly and to represent or evidence sufficient financing in order toparticipate, as the Trustee expects payment will be required promptly after theclose of bidding without any financing conditions. Accordingly, the auction maynot be a “public” auction in the sense that it may not be open to anyone whodoes not satisfy these requirements. The Trustee is currently reviewing apotential online bidding process for participants in order to provide currentpublic information on bidding to the marketplace. The Trustee will alsodetermine a duration of bidding that it deems in the best interest of theunitholders.

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

The Trustee currently expects to commence the saleprocess in the latter half of 2005, after its receipt of additional oil and gasreserve information for the production test on the Brazos A-39 exploratoryprospect (see “Description of the Royalty Properties—Exploration update” below)and the completion of the joint venture audit referred to above. The Trustee iswaiting for this information to ensure as much information as possibleregarding the Royalty Properties is available for bidders in connection with asale.

For more informationregarding the estimated remaining life of each of the Royalty Properties, theestimated future net revenues of the Royalty Properties and informationrelating to farm-outs of interests on the Royalty Properties based oninformation provided by PNR, see pages 23 and 24 of this Form 10-Kand Note 7 in the Notes to Financial Statements included elsewhere in this Form 10-K.The sale of the assets of the Trust estate will include the related rights toabandonment accruals made by PNR. As explained in “Regulation and Prices—PlatformAbandonment and Removal” below, PNR withholds from the Trust a reserve to coverits share of those future abandonment and removal costs. To the extent acertain party is able to complete the abandonment for an amount less than thefunds withheld by PNR, the related rights to the abandonment accrual are likelyto be deemed marketable. The final distribution to unitholders will be anamount net of funds required to satisfy all Trust liabilities.

**DESCRIPTION OF ROYALTY PROPERTIES**

**Producing Acreage and Wells as of December 31,2004**
| ** **                   | ** ** | ** **               | ** ** | ** ** | ** ** | **Producing Wells(1)** | ** ** |
|------------------------------|------------|--------------------------|------------|------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **Producing Acres** | ** ** | **Gross**  | ** ** | **Net**                     | ** ** |
| **Property**                 | ** ** | ** **               | ** ** | **Gross**  | ** ** | **Net(2)**                  | ** ** | **Oil** | ** ** | **Gas** | ** ** | **Oil** | ** ** | **Gas** | ** ** |
| Offshore  Louisiana(3)— |       |                     |       |       |       |                        |       |   |   |   |   |   |   |
| West Delta 61                |       | 5,000                    |       | 3,750      |       | —                      |       | 4 |   | — |   | .4 |   |
| Offshore Texas(4)—      |       |                     |       |       |       |                        |       |   |   |   |   |   |   |
| Brazos A-7                   |       | 5,760                    |       | 2,160      |       | —                      |       | 1 |   | — |   | .1 |   |
| Brazos A-39                  |       | 5,760                    |       | 2,160      |       | —                      |       | — |   | — |   | — |   |
| Total                        |       | 16,520                   |       | 8,070      |       | —                      |       | 5 |   | — |   | .5 |   |
|                              |            |                          |            |            |            |                             |            |  |  |  |  |  |  |  |  |

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(1)          Dual completions arecounted as one well. For information regarding wells producing at December 31,2004, see “Net Proceeds, Production and Average Prices” on page 29 of thisForm 10-K. As of March 31, 2005, only the wells on Brazos A-7and West Delta 61 were producing.

(2)          Net Producing Acres arecalculated by multiplying gross producing acres by the net Royalty interest (asdefined by the Trust Indenture) attributable to the Trust for each property.

(3)          All wells on South MarshIsland 155 and 156 leases were plugged and abandoned in 2002. PNR abandoned theplatform for these two properties in 2003. All wells were plugged and abandonedand the platform was abandoned on West Delta 62 during 2003 and the lease wasrelinquished.

(4)          Allwells were plugged and abandoned and the platform was abandoned on MatagordaIsland 624 during 2003 and the lease was relinquished.

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**Exploration update**

***Brazos A-39 (Midway prospect)***

PNR advised the Trust thatit farmed out the Trust’s interest in Brazos A-39 so that exploratoryprospects could be drilled. Drilling commenced on the exploration prospect in September 2003and was announced as a discovery in the first quarter of 2004. PNR approved aplan to set minimal facilities, complete the well and perform a production testprior to determining whether or not to develop the project as a subsea tie-backinto an existing platform. The production test was successfully completedduring the first quarter of 2005. PNR has informed the Trust that the lowerhorizon of the prospect was determined to be non-commercial, while middlehorizon produced at 10 million cubic feet of gas a day during a 17 hour flowtest. There is no assurance that these flow rates will continue, as offshoreoil and gas properties often experience stronger initial flow rates and morerapid declines than onshore properties. PNR expects to tie-back this prospectinto an existing platform, operated by a third party, with first productionexpected to commence by the fourth quarter of 2005. As of December 31,2004, PNR has not attributed any proved oil and gas reserves to this prospect. However,as a result of the successful production test, PNR is currently evaluating thequantity of proved reserves to be assigned. PNR and Woodside Energy (USA), Inc.,a wholly owned subsidiary of Woodside Petroleum Ltd., each own a 50% workinginterest in this well (OCS-G 4559 #5).

***West Delta 61***

PNR has advised the Trustthat Stone Energy Corporation (“Stone”) recompleted an exploratory well on WestDelta 61 that was placed on production early in the third quarter of 2004.

***Other Properties***

PNR has advised the Trustthat it is not aware of any other exploration opportunities and currently hasno other planned exploratory drilling projects, farm-outs or joint ventures forexploratory drilling projects under discussion, for the Royalty Properties.

**Reserves**

A study of the proved oil and gas reservesattributable to the Partnership as of December 31, 2004, has been made byPNR. The following letter (the “Reserve Report”) summarizes such reserve study.The Reserve Report reflects estimated reserve quantities and future net revenuebased upon estimates of the future timing of actual production without regardto when received in cash by the Trust, which differs from the manner in whichthe Trust recognizes and accounts for its royalty income. For furtherinformation regarding the Net Overriding Royalty Interest, the Basis ofAccounting for the Trust and Supplemental Reserve Information, see Notes 2, 3and 6, respectively, in the Notes to Financial Statements contained in Item 8of this Form 10-K.

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March 1, 2005

MESA Offshore TrustJPMorgan Chase Bank (as Trustee)700 Lavaca Street, 5th FloorAustin, Texas 78701-3102

Ladies and Gentlemen:

Pursuant to your request, we have prepared estimates,as of December 31, 2004, of the extent and value of the proved crude oil,condensate, natural gas liquids, and natural gas reserves of certain propertiessubject to a net profits interest owned by the Mesa Offshore Royalty Partnership,hereinafter referred to as the “Partnership,” a partnership owned 99.99 percentby the Mesa Offshore Trust. The interest appraised is referred to herein as the“Partnership Interest” and consists of a 90 percent net profits interest inthree Pioneer Natural Resources USA, Inc. (hereinafter referred to as “Pioneer”)leases located in the Gulf of Mexico offshore from Louisiana and Texas. Thethree offshore leases subject to the net profits interest are hereinafterreferred to as the “Subject Properties.” Reserves of the three leases arereported herein.

The reserve estimates are based on a detailed study ofthe Subject Properties. The method or combination of methods used in the studyof each reservoir was tempered by experience in the area, consideration of thestage of development of the reservoir, and the quality and completeness ofbasic data.

Estimates of oil, condensate, natural gas liquids andgas reserves and future net revenue should be regarded only as estimates thatmay change as further production history and additional information becomeavailable. Not only are such reserve and revenue estimates based on thatinformation which is currently available, but such estimates are also subjectto the uncertainties inherent in the application of judgment factors ininterpreting such information.

In the preparation of this report, Pioneer has usedinternal information with respect to property interests owned by thePartnership, production from such properties, current costs of operation anddevelopment, current prices for production, agreements relating to current andfuture operations and sale of production, and various other information.

The development status shown herein represents thestatus applicable as of December 31, 2004. Data available from wellsdrilled on the appraised properties through December 31, 2004 was used inestimating gross ultimate recovery. Gross production estimated to December 31,2004, was deducted from gross ultimate recovery to arrive at the estimates ofgross reserves. In some fields, this required that the production rates beestimated for a portion of 2004 since production data for these properties wasnot available throughout 2004.

The reserve volumes and revenue values shown in thisreport for Partnership Interest were estimated from projections of reserves andrevenue attributable to the combined interests consisting of the PartnershipInterest and the retained Pioneer Interest in the Subject Properties (CombinedInterest). Net reserves attributable to the Partnership Interest were estimatedby allocating to the Partnership a portion of the estimated combined netreserves of the Subject Properties based on future revenue. Therefore, the 

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estimated net reservesattributable to the Partnership Interest will vary if different future priceand cost assumptions are used.

While estimates of reserves attributable to the Trustare shown in order to comply with requirements of the SEC, there is no precisemethod of allocating estimates of physical quantities of reserves between theworking interest owners and the Trust. The net profits overriding royaltyinterest is not a working interest and the Trust does not own and is notentitled to receive any specific volume of reserves from the Trust. Thequantities of reserves attributable to the Trust will be affected by futurechanges in various economic factors utilized in estimating future gross and netrevenues from the Trust Properties. Therefore, the estimates of reserves setforth in the Reserve Reports are to a large extent hypothetical and differ insignificant respects from estimates of reserves attributable to a workinginterest.

Petroleum reservesincluded in this report are classified as proved and are judged to beeconomically producible in future years from known reservoirs under existingeconomic and operating conditions and assuming continuation of currentregulatory practices using conventional production methods and equipment. Inthe analysis, reserves were estimated only to the limit of economic rates ofproduction under existing economic and operating conditions using prices andcosts as of the date the estimate is made, including consideration of changesin existing prices provided only by contractual arrangements but not includingescalations based upon future conditions. The petroleum reserves are classifiedas follows:

·       Proved—Reservesthat have been proved to a high degree of certainty by analysis of theproducing history of a reservoir and/or by volumetric analysis of adequategeological and engineering data. Commercial productivity has been establishedby actual production, successful testing, or in certain cases by favorable coreanalyses and electrical-log interpretation when the producing characteristicsof the formation are known from nearby fields. Volumetrically, the structure,areal extent, volume, and characteristics of the reservoir are well defined bya reasonable interpretation of adequate subsurface well control and by knowncontinuity of hydrocarbon-saturated material above known fluid contacts, if any,or above the lowest known structural occurrence of hydrocarbons.

·       Developed—Reservesthat are recoverable from existing wells with current operating methods andexpenses. Developed reserves include both producing and nonproducing reserves. Estimatesof producing reserves assume recovery by existing wells producing from presentcompletion intervals with normal operating methods and expenses. Developednonproducing reserves are in reservoirs behind the casing or at minor depthsbelow the producing zone and are considered proved by production from otherwells in the field, by successful drill-stem tests, or by core analysis fromthe particular zones. Nonproducing reserves require only moderate expense to bebrought into production.

·       Undeveloped—Reservesthat are recoverable from additional wells yet to be drilled. Undevelopedreserves are those considered proved for production by reasonable geologicalinterpretation of adequate subsurface control in reservoirs that are producingor proved by other wells but are not recoverable from existing wells. Thisclassification of reserves requires drilling of additional wells, majordeepening of existing wells, or installation of enhanced recovery or otherfacilities.

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Estimates of the netproved reserves attributable to the Partnership Interest, as of December 31,2004, are as follows:
| TOTAL, PROVED RESERVES  (PDP+PNP):         |   |    |   |
|--------------------------------------------|--------|---------|--------|
| Natural Gas (Mcf)                          |   | 174,510 |   |
| Oil and Condensate (bbl)                   |   | 5,960   |   |
| Natural Gas Liquids  (bbl)                 |   | 0       |   |
| PROVED DEVELOPED  PRODUCING RESERVES (PDP) |   |    |   |
| Natural Gas (Mcf)                          |   | 174,510 |   |
| Oil and Condensate (bbl)                   |   | 5,960   |   |
| Natural Gas Liquids  (bbl)                 |   | 0       |   |

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*                    Reservecalculation found in Table 1 and Table 2

Revenue values attributable to the net proved reservesof the Partnership Interest are expressed in terms of estimated future netrevenue and present worth of future net revenue. Future net revenueattributable to the Partnership Interest was estimated monthly from aprojection of the combined Pioneer and Partnership future net revenue. Combinedfuture net revenue values were calculated by deducting operating expenses andcapital costs from the future gross revenue of the Combined Interest. Themonthly values for the aggregate of the Combined Interest in the SubjectProperties were reduced by an overhead charge, by a monthly amount necessaryfor Pioneer to accrue the abandonment costs over the life of the properties, bythe deficit balance as described below from the previous month, and by theinterest on that deficit balance when such deficits occur. If the adjustedrevenue resulting from this calculation was negative, it was carried forward tothe next month as a deficit balance. If the adjusted revenue was greater thanzero, it was multiplied by a factor of 90 percent to arrive at the future netrevenue of the Partnership Interest. The above calculations were made monthlyin the aggregate for the Subject Properties. As of December 31, 2004 thePartnership Interest has a deficit balance of $59,035. Although interest ischargeable monthly on the net profits deficit balance at an amount equal to theweighted average prime interest rate in effect during the period of suchoverpayment plus one-half of one percentage point, Pioneer has not charged thePartnership interest on the deficit balance.

Future oil and gas producing rates estimated for thisreport are based on production rates considering the most recent figuresavailable or, in certain cases, are based on estimates tempered by Pioneer’sexperience in the area. The rates used for future production are rates thatPioneer has determined are within the capacity of the well or reservoir toproduce.

Gas volumes shown herein are expressed at standardconditions of 60 degrees Fahrenheit and a 15.025 pounds per square inchabsolute. Condensate reserves estimated herein are those to be obtained fromnormal separator recovery.

Revenue values in this report were estimated usingcurrent prices and costs. Future prices were estimated using guidelinesestablished by the Securities and Exchange Commission and the FinancialAccounting Standards Board.

The assumptionsused for estimating future prices and costs are as follows:

·       Oiland Condensate Prices—Oil and condensate prices were held constant for the lifeof the properties.

·       NaturalGas Prices—Gas prices were held constant for the life of the properties.

·       NaturalGas Liquids Prices—Natural gas liquids prices were held constant for the lifeof the properties.

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·       Operatingand Capital Costs—Current estimates of operating costs were used for the lifeof the properties with no increases in the future based on inflation. Futurecapital expenditures were estimated using 2004 values and were not adjusted forinflation.

Asummary of estimated revenue and costs attributable to the Combined Interest inproved reserves and the future net revenue and present worth attributable tothe Partnership Interest, as of December 31, 2004 is as follows:
| COMBINED INTEREST:                               |   |          |   |
|--------------------------------------------------|--------|---------------|--------|
| Future Gross Revenue ($)                         |   | 2,009,273     |   |
| Production and Ad Valorem Taxes ($)              |   | 0             |   |
| Operating Costs ($)                              |   | 522,000       | >   |
| Capital Costs ($)(1)                             |   | <2,973,501 | >   |
| Future Net Expense ($)                           |   | <1,486,228 | >   |
| Accrued Revenue for Abandonment Costs ($)        |   | 2,973,501     |   |
| Future Accrued Revenue for Abandonment Costs ($) |   | 0             |   |
| Cumulative Net Profits Deficit @ 12/31/04        |   | <65,594    | >   |
| Revenue Subject to Net Profits Interest ($)      |   | 1,421,679     |   |
| PARTNERSHIP  INTEREST:                           |   |          |   |
| Future Net Revenue ($)(2)                        |   | 1,279,511     |   |
| Present Worth at  10 Percent ($)                 |   | 1,103,896     |   |

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(1)          Issolely made up of future abandonment costs.

(2)          Futureincome tax expenses were not taken into account in the preparation of theseestimates.

The information relating to estimated proved reserves,estimated future net revenue from proved reserves, and present worth ofestimated future net revenue from proved reserves of oil, condensate, naturalgas liquids, and gas contained in this report has been prepared in accordancewith Paragraphs 10-13, 15 and 30(a)-(b) of Statement of FinancialAccounting Standards No. 69 (November 1982) of the FinancialAccounting Standards Board and Rules 4-10(a)(l)-(13) of Regulation S-X andRule 302(b) of Regulation S-K of the Securities and ExchangeCommission; provided, however, future income tax expenses have not been takeninto account in estimating the future net revenue and present worth values setforth herein.

To the extent the above enumerated rules, regulations,and statements require determinations of an accounting or legal nature orinformation beyond the scope of this report, we are necessarily unable to expressan opinion as to whether the above-described information is in accordancetherewith or sufficient therefore.

Submitted,

/s/ PAUL MCDONALD

PaulMcDonald

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There are numerous uncertainties inherent inestimating quantities of proved reserves and in projecting the future rates ofproduction and timing of development expenditures, including many factorsbeyond the control of the producer. The preceding reserve data in the ReserveReport represent estimates only and should not be construed as being exact. Reserveassessment is a subjective process of estimating the recovery from undergroundaccumulations of gas and oil that cannot be measured in an exact way andestimates of other persons might differ materially from those of PNR.Accordingly, reserve estimates are often different from the quantities ofhydrocarbons that are ultimately recovered.

Also, while estimates of reserves attributable to theRoyalty Properties are shown in order to comply with requirements of the SEC,there is no precise method of allocating estimates of physical quantities ofreserves between PNR and the Partnership, since the Royalty is not a workinginterest and the Partnership does not own and is not entitled to receive anyspecific volume of reserves from the Royalty. Reserve quantities in thepreviously mentioned reserve study have been allocated based on the methodreferenced in the Reserve Report. The quantities of reserves attributable tothe Partnership will be affected by future changes in various economic factorsutilized in estimating future gross and net revenues from the RoyaltyProperties. Therefore, the estimates of reserves set forth in the ReserveReport are to a large extent hypothetical and differ in significant respectsfrom estimates of reserves attributable to a working interest.

Moreover, the discounted present values in the ReserveReport should not be construed as the current market value of the estimated gasand oil reserves attributable to the Royalty Properties or the costs that wouldbe incurred to obtain equivalent reserves, since a market value determinationwould include many additional factors. In accordance with applicableregulations of the SEC, estimated future net revenues were based, generally, oncurrent prices and costs, whereas actual future prices and costs may bematerially greater or less. The estimates in the Reserve Report use marketprices as of December 31, 2004. These prices (having a weighted averageyear end price of $43.33 per barrel and $6.19 per Mcf as of December 31,2004) were held constant over the estimated life of the Royalty Properties.These prices were influenced by seasonal demand for natural gas and may not bethe most appropriate or representative prices to use for estimating futurerevenues or related reserve data. The average price of natural gas sold fromthe Royalty Properties during 2004 was $5.38 per Mcf, representing acombination of contract prices and spot market prices, while the average priceof crude oil, condensate and natural gas liquids was $32.57 per barrel.

Thefollowing is a summary of the estimated remaining life for each of the RoyaltyProperties provided to the Trustee by PNR as of December 31, 2004. Thereare numerous uncertainties present in estimating the remaining productive livesfor the Royalty Properties. The following summary represents an estimate onlyand should not be construed as being exact. The estimated remaining productivelife of each property varies depending on the recoverable reserves and annualproduction assumed by PNR. In addition, future economic and operatingconditions may cause significant changes in these estimates.
| **Property**  | ** ** | ** ** | ** ** | **Productive Life(1)(2)** | ** ** |
|---------------|------------|------------|------------|--------------------------------|------------|
| West Delta 61 |       |       | 7 years    |                           |       |
| Brazos A-7    |       |       | 1 year     |                           |       |
| Brazos A-39   |       |       | None       |                           |       |

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(1)          TheTrust will terminate in the event the total amount of cash received per year bythe Trust falls below certain levels. Accordingly, it would be possible for theTrust to terminate even though some of the Royalty Properties continued to haveremaining productive lives. See “Termination of the Trust” on page 8 ofthis Form 10-K.

(2)          Estimatesof remaining lives may vary significantly from year to year.

The future net revenues contained in the ReserveReport have not been reduced for future general and administrative costs andexpenses of the Trust, which are expected to approximate $500,000 annually. 

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The general andadministrative costs and expenses of the Trust may increase in future years,depending on the amount of royalty income, increases in accounting,engineering, legal and other professional fees and other factors.

**Proceeds,Production and Average Prices**

Reference is made to “NetProceeds, Production and Average Prices” under Item 7 of this Form 10-K.

**CONTRACTS**

**General**

PNR has advised the Trustthat during 2004 its offshore gas production was marketed under short-termcontracts at spot market prices primarily to Occidental Petroleum Corp. andTotal S.A. PNR has further advised the Trust that it expects to continue tomarket its production under short-term contracts for the foreseeable future.Spot market prices for natural gas in 2004 were generally higher than spotmarket prices in 2003.

**Market for NaturalGas**

The amount of cash distributions by the Trust isdependent on, among other things, the sales prices for natural gas producedfrom the Royalty Properties and the quantities of gas sold. The natural gasindustry in the United States during the 1990’s was affected generally by asurplus in natural gas deliverability in comparison to demand. Demand for gasdeclined during this period due to a number of factors including theimplementation of energy conservation programs, a shift in economic activityaway from energy intensive industries and competition from alternative fuelsources such as residual fuel oil, coal and nuclear energy. In late 2001 andearly 2002, demand for natural gas increased as a result of the increase inclean burning natural gas fired power generation, the increase in the usage ofelectrical power fueled by the expanding U.S. economy and a return toseasonally cold winters. Annual wellhead prices generally increased from $3.69per Mcf in 2000 to $4.02 per Mcf in 2001, decreased to $2.95 per Mcf in 2002,increased to $5.09 per Mcf in 2003, and increased to $5.49 per Mcf in 2004according to the Natural Gas Monthly published by the Energy InformationAdministration of the Department of Energy.

The seasonal nature ofdemand for natural gas and its effects on sales prices and production volumesmay cause the amounts of cash distributions by the Trust to vary substantiallyon a seasonal basis. Generally, production volumes and prices are higher duringthe first and fourth quarters of each calendar year due primarily to peakdemand in these periods. Because of the time lag between the date on which PNRreceives payment for production from the Royalty Properties and the date onwhich distributions are made to unitholders, the seasonality that generallyaffects production volumes and prices is generally reflected in distributionsto unitholders in later periods.

**Competition**

The production and sale ofgas from the areas in which the Royalty Properties are located is highlycompetitive and PNR has a number of competitors in these areas. PNR has advisedthe Trust that it believes that its competitive position in these areas isaffected by price, contract terms and quality of service. PNR’s business isaffected not only by such competition, but also by general economicdevelopments, governmental regulations and other factors.

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**Marketing ofLiquids**

PNR generally reserves inits gas purchase contracts the right to extract condensate and other liquid andliquifiable hydrocarbons from all gas produced. PNR is currently selling thecondensate and other liquids to various purchasers under contracts with termsof one year or less.

**REGULATIONAND PRICES**

**General**

The production and sale ofnatural gas from the Royalty Properties are affected from time to time invarying degrees by political developments and federal, state and local laws andregulations. In particular, oil and gas production operations and economicsare, or in the past have been, affected by price controls, taxes, conservation,safety, environmental and other laws relating to the petroleum industry, bychanges in such laws and by constantly changing administrative regulations.

**Operating Hazardsand Uninsured Risks**

PNR’s oil and gasactivities are subject to all of the risks normally incident to exploration forand production of oil and gas, including blowouts, cratering and fires, each ofwhich could result in damage to life and property. Offshore operations aresubject to a variety of operating risks, such as hurricanes and other adverseweather conditions and lack of access to existing pipelines or other means oftransporting production. Furthermore, offshore oil and gas operations aresubject to extensive governmental regulations, including certain regulationsthat may, in certain circumstances, impose absolute liability for pollutiondamages, and to interruption or termination by governmental authorities based onenvironmental or other considerations. In accordance with customary industrypractices, PNR carries insurance against some, but not all, of these risks.Losses and liabilities resulting from such events would reduce revenues andincrease costs to the Trust to the extent not covered by insurance.

**FERC Regulation**

In general, the FERCregulates the transportation of natural gas in interstate commerce byinterstate pipelines. Over the course of approximately the previous decade, theFERC adopted regulations resulting in a restructuring of the natural gasindustry. The principal elements of this restructuring were the requirementsthat interstate pipelines separate, or “unbundle,” into individual componentsthe various services offered on their systems, with all transportation servicesto be provided on a non-discriminatory basis, and the prohibition against aninterstate pipeline providing gas sales services except throughseparately-organized affiliates. In various rulemaking proceedings followingits initial unbundling requirement, the FERC has refined its regulatory programapplicable to interstate pipelines in various respects, and it has announcedthat it will continue to monitor these regulations to determine whether furtherchanges are needed. As to these various developments, the working interestowners have advised the Trust that the on-going and evolving nature of theseregulatory initiatives makes it impossible to predict their ultimate impact onthe prices, markets or terms of sale of natural gas related to the Trust.

**State and OtherRegulation**

State regulation of gathering facilities generallyincludes various safety, environmental, and in some circumstances,non-discriminatory take requirements. Some states have implemented morestringent legislation in recent years to regulate gathering rates charged bygas gathering companies, but to date the effect to PNR in connection with theRoyalty Properties has been minimal.

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Natural gas pipelinefacilities used for the transportation of natural gas in interstate commerceare subject to Federal minimum safety requirements. These requirements,however, are not applicable to, *inter alia*,:(1) onshore gathering facilities outside: (i) the limits of anyincorporated or unincorporated city, town, or village; and (ii) anydesignated residential or commercial area; or (2) pipeline facilities onthe Outer Continental Shelf (“OCS”) upstream of the point at which operatingresponsibility transfers from a producing operator to a transporting operator. *See* 49 C.F.R. § 192.1(b). We are informedthat the Royalty Properties are located in Federal waters on the OCS. Thestandards governing pipeline safety have undergone recent changes and it is possiblethat future changes in the regulations and statutes may occur which mayincrease the stringency of the standards or expand the applicability of thestandards to facilities not currently covered.

**Environmental**

PNR’s operations are subject to numerous federal,state and local laws and regulations controlling the discharge of materialsinto the environment or otherwise relating to the protection of theenvironment, including the Comprehensive Environmental Response, Compensationand Liability Act (“CERCLA” or “Superfund”), the Solid Waste Disposal Act, theClean Air Act, and the Federal Water Pollution Control Act. These laws andregulations, including their state counterparts, can impose liability upon thelessee under a lease for the cost of cleanup of discharged materials resultingfrom a lessee’s operations or can subject the lessee to liability for damagesto natural resources. Violations of environmental laws, regulations, or permitscan result in civil and criminal penalties as well as potential injunctionscurtailing operations in affected areas and restrictions on the injection ofliquids into the subsurface that may contaminate groundwater. PNR maintainsinsurance for costs of cleanup operations, but it is not fully insured againstall such risks. A serious release of regulated materials could result in theU.S. Department of the Interior requiring lessees under federal leases tosuspend or cease operations in the affected area. In addition, the recent trendtoward stricter standards and regulations in environmental legislation islikely to continue. For example, legislation has been proposed in Congress thatwould reclassify certain oil and gas production wastes as “hazardous wastes”which would subject the handling, disposal and cleanup of these wastes to morestringent requirements and result in increased operating costs for the RoyaltyProperties, as well as the oil and gas industry in general. State initiativesto further regulate the disposal of oil and gas wastes are also pending incertain states, and these initiatives could have a similar impact on theRoyalty Properties.

From time to time, federal and state environmentalagencies propose regulations which could have a direct and material impact onPNR’s operations. For example, under the Oil Pollution Act of 1990, as amendedby the Coast Guard Authorization Act of 1996 (collectively, “OPA”), partiesresponsible for offshore facilities must establish and maintain evidence ofoil-spill financial responsibility (“OSFR”) for costs attributable to potentialoil spills. OPA requires a minimum of $35 million in OSFR for offshorefacilities located on the OCS. This amount is subject to upward regulatoryadjustment up to $150 million. Responsible parties for more than oneoffshore facility are required to provide OSFR only for their offshore facilityrequiring the highest OSFR. In 1998, the Minerals Management Service (“MMS”)adopted regulations for establishing the amount of OSFR required for particularfacilities. The amount of OSFR increases as the volume of a facility’sworst-case oil spill increases. Accordingly, for facilities with worst-casespills of less than 35,000 barrels, only $35 million in OSFR is required;for worst-case spills of over 35,000 barrels, $70 million is required; forworst-case spills of over 70,000 barrels, $105 million is required; andfor worst-case spills of over 105,000 barrels, $150 million is required.In addition, all OSFR below $150 million remains subject to upwardregulatory adjustment if warranted by the particular operational,environmental, human health or other risks involved with a facility. Under thisregulation, PNR is required to maintain $35 million in OSFR for itsoffshore facilities. PNR is maintaining its OSFR in this amount by insurance.Although the working interest owners have advised the Trust that currentenvironmental regulation has had no material adverse effect on the workinginterest owners’ present 

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method of operations, theimpact of the recently adopted regulatory changes, and of future environmentalregulatory developments such as stricter environmental regulation andenforcement policies, cannot presently be quantified. By letter dated November 9,1995, PNR was advised by the MMS that it does not qualify for a waiver fromsupplemental bond requirements and that PNR may be required to postsupplemental bonds covering its potential obligations with respect to offshoreoperations. PNR executed a guaranty of abandonment liability (area wide) withthe MMS on April 26, 1996, in satisfaction of these obligations.

PNR has advised the Trustthat it is not involved in any administrative or judicial proceedings relatingto the Royalty Properties arising under federal, state, or local environmentalprotection laws and regulations which would have a material adverse effect onthe Trust’s financial position or results of operations.

**PlatformAbandonment and Removal**

PNR is responsible for theabandonment and removal of its offshore drilling and production structureswithin one year after the cessation of production, although extensions can berequested. PNR withholds from the Trust a reserve to cover its share of thosefuture abandonment and removal costs. See Item 7 and Note 6 in theNotes to Financial Statements for amounts withheld as of December 31, 2004and amounts to be withheld in the future.

**PRINCIPALTRUST RISK FACTORS**

Although risk factors are described elsewhere in this Form 10-Ktogether with specific Cautionary Statements, the following is a summary of theprincipal risks associated with an investment in units in the Trust.

**Natural gas and oilprices fluctuate due to a number of factors, and lower prices will reduce netproceeds available to the Trust and distributions to Trust unitholders.**

The Trust’s quarterly distributions are highlydependent upon the prices realized from the sale of natural gas and oil.Natural gas and oil prices can fluctuate widely on a month-to-month basis inresponse to a variety of factors that are beyond the control of the Trust andthe working interest owners. Factors that contribute to price fluctuationinclude, among others: political disruption, war, or other armed conflict inoil producing regions, in particular the war in Iraq; worldwide economicconditions; weather conditions; the supply and price of foreign natural gas andoil; the level of consumer demand; the price and availability of alternativefuels; the proximity to, and capacity of, transportation facilities; and theeffect of worldwide energy conservation measures.

Moreover, government regulations, such as regulationof natural gas and oil transportation and price controls, can affect productprices in the long term.

Lower natural gas and oil prices may reduce the amountof natural gas that is economic to produce and reduce net profits available tothe Trust. The volatility of energy prices reduces the predictability of futurecash distributions to unitholders. Substantially all of the natural gas andnatural gas liquids produced from the Royalty Properties is being sold on thespot market or under short-term contracts.

**Increasedproduction and development costs for the Royalty will result in decreased Trustdistributions.**

Production and development costs attributable to theRoyalty are deducted in the calculation of the Trust’s share of net proceeds.Accordingly, higher or lower production and development costs, withoutconcurrent increases in revenues, directly decrease or increase the amountreceived by the Trust for the Royalty.

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If development and production costs of the Royaltyexceed the proceeds of production from the Royalty Properties, the Trust willnot receive net proceeds for those properties until future proceeds fromproduction exceed the total of the excess costs plus accrued interest duringthe deficit period. Development activities may not generate sufficientadditional revenue to repay the costs.

**Trust reserveestimates depend on many assumptions that may prove to be inaccurate, whichcould cause both estimates of reserves and estimated future revenues to be toohigh.**

The value of theunits of beneficial interest of the Trust depends upon, among other things, theamount of reserves attributable to the Royalty and the estimated future valueof the reserves. Estimating reserves is inherently uncertain. Ultimately,actual production, revenues and expenditures for the underlying properties willvary from estimates and those variations could be material. Petroleum engineersconsider many factors and make assumptions in estimating reserves. Thosefactors and assumptions include:

·       historicalproduction from the area compared with production rates from similar producingareas;

·       theassumed effect of governmental regulation; and

·       assumptionsabout future commodity prices, production and development costs, severance andexcise taxes, and capital expenditures.

Changes in these assumptions can materially changereserve estimates.

The reserve quantities attributable to the Royalty andrevenues are based on estimates of reserves and revenues for the underlyingproperties. The method of allocating a portion of those reserves to the Trustis complicated because the Trust holds an interest, indirectly through thePartnership, in the Royalty and does not own a specific percentage of thenatural gas reserves.

**Estimates andaccruals of abandonment costs by PNR may be greater or lesser than futureestimated or actual costs.**

As discussed in Item 7 and Note 6 to theNotes to Financial Statements, at December 31, 2004 PNR has withheldapproximately $2,676,151 for future abandonment costs. To the extent futureestimated or actual abandonment costs exceed this amount, PNR would be entitledto withhold such amounts from payments with respect to the Royalty. Similarly,to the extent future estimated or actual abandonment costs are less than thisamount, PNR may release such amounts. In connection with the termination of theTrust and sale of the Royalty Properties, the rights to these accruedabandonment costs will be included together with the other assets being sold. Onlyunitholders at the time of any such release or sale and the applicabledistribution would be entitled to the distribution by the Trust.

**Operating risks forthe working interest owners’ interests in the Royalty Properties can adverselyaffect Trust distributions.**

The occurrence of drilling, production or transportationaccidents at any of the Royalty Properties will reduce Trust distributions bythe amount of uninsured costs. These occurrences include blowouts, cratering,explosions and other environmental damage. Offshore activities are also subjectto a variety of operating risks such as hurricanes and other weatherdisturbances. These accidents and other natural disasters may result inpersonal injuries, property damage, damage to productive formations orequipment and environmental damages. Any uninsured costs would be deducted as aproduction cost in calculating net proceeds payable to the Trust.

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**The operators of the working interest owner aresubject to extensive governmental regulation.**

Offshore oil and gas operations have been, and in thefuture will be, affected by federal, state and local laws and regulations andother political developments, such as price or gathering rate controls andenvironmental protection regulations.

**None of theTrustee, the Trust nor its unitholders control the operation or development ofthe Royalty Properties and have little influence over operation or development.**

Neither the Trustee nor the unitholders can influenceor control the operation or future development of the underlying properties.The Royalty Properties are owned by PNR as an independent working interestowner. The working interest owner manages the underlying properties and handlesreceipt and payment of funds relating to the Royalty Properties and payments tothe Trust for the Royalty.

PNR, as the current working interest owner, is underno obligation to continue operating the properties. Neither the Trustee nor theunitholders have the right to replace an operator.

**The owner of anyRoyalty Property may abandon any property, terminating the related Royalty.**

The working interest owner may at any time transferall or part of the Royalty Property to another unrelated third party.Unitholders are not entitled to vote on any transfer, and the Trust will notreceive any proceeds of any such transfer. Following any transfer, the RoyaltyProperties will continue to be subject to the Royalty, but the net proceedsfrom the transferred property would be calculated separately and paid by thetransferee. The transferee would be responsible for all of the obligationsrelating to calculating, reporting and paying to the Trust the Royalty on thetransferred portion of the Royalty Properties, and the current owner of theRoyalty Properties would have no continuing obligation to the Trust for thoseproperties.

The current working interest owner or any transfereemay abandon any well or property if it reasonably believes that the well orproperty can no longer produce in commercially economic quantities. This couldresult in termination of the Royalty relating to the abandoned well. Please see“Business—Termination of the Trust” in Item 1 of this Form 10-K.

**The Royalty will besold and the Trust is being terminated.**

The Trust is being terminated and the Trustee mustsell the Royalty as the total amount of cash received per year by the Trust foreach of three consecutive years ending December 31, 2004 was less than theTermination Threshold. Following this termination and liquidation, the netproceeds of any sale will be distributed to the unitholders and unitholderswill receive no further distributions from the Trust. We cannot assure you thatany such sale will be on terms acceptable to all unitholders. See Item 1 ofthis Form 10-K under “Business—Termination of the Trust.”

**Trust assets aredepleting assets and, if the working interest owners or other operators of theRoyalty Properties do not perform additional development projects, the assetsmay deplete faster than expected.**

The net proceeds payable to the Trust are derived fromthe sale of depleting assets. Accordingly, the portion of the distributions tounitholders attributable to depletion may be considered a return of capital.The reduction in proved reserve quantities is a common measure of depletion.Future maintenance and development projects on the Royalty Properties willaffect the quantity of proved reserves. The timing and size of these projectswill depend on the market prices of natural gas. If the operator of the RoyaltyProperties does not implement additional maintenance and development projects,the future rate of production decline of proved reserves may be higher than therate currently expected by the Trust. For federal income tax purposes,depletion is reflected as a deduction, which is dependent upon the purchaseprice of a unit. Please see the section entitled “Business—Description of theUnits—Federal Income Tax Matters” in Item 1 of this Form 10-K under “Business”.

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**Unitholders havelimited voting rights.**

Voting rights as a unitholder are more limited thanthose of stockholders of most public corporations. For example, there is norequirement for annual meetings of unitholders or for an annual or otherperiodic re-election of the Trustee. Unlike corporations which are generallygoverned by boards of directors elected by their equity holders, the Trust isadministered by a corporate Trustee in accordance with the Trust Indenture andother organizational documents. The Trustee has extremely limited discretion inits administration of the Trust.

**Unitholders havelimited ability to enforce the Trust’s rights against the current or futureowners of the Royalty Properties.**

The Trust Agreement andrelated trust law permit the Trustees and the Trust to sue the working interestowner to compel it to fulfill the terms of the Conveyance of the Royalty. Ifthe Trustee does not take appropriate action to enforce provisions of theConveyance, the recourse of a unitholder would likely be limited to bringing alawsuit against the Trustee to compel the Trustee to take specified actions.Unitholders probably would not be able to sue the working interest ownerdirectly.

**Item 2.**                        Properties.

Reference is made to Item1 of this Form 10-K.

**Item 3.**                        LegalProceedings.

There are no pending legalproceedings to which the Trust is a party.

**Item 4.**                        Submissionof Matters to a Vote of Security Holders.

There were no matters submitted to a vote ofunitholders during the fourth quarter of 2004.

22

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**PART II**

**Item 5.**                        Market forthe Registrant’s Common Equity and Related Unitholder Matters.

Theunits of beneficial interest of the Trust were delisted from the PacificExchange effective May 18, 2001. The Trust units are currently eligiblefor trading on the OTC Bulletin Board under ticker symbol MOSH. There was nodistribution of income for the year ended December 2004, due to a deficitbalance owed to PNR. The high and low sales prices and distributions per unitfor each quarter in the two years ended December 31, 2004 were as follows:
| ** **     | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|----------------|------------|------------|------------|------------|------------|
| ** **     | ** ** | ** ** | ** ** | ** ** | ** ** | **Distribution** | ** ** | ** ** | ** ** | ** ** | ** ** | **Distribution** | ** ** |
| ** **     | ** ** | **High**   | ** ** | **Low**    | ** ** | **Paid** | ** ** | **High** | ** ** | **Low** | ** ** | **Paid** | ** ** |
| First Quarter  |       | $          | 0.05       |       | $          | 0.03 |   |   | $ | — |   |   | $ | 0.07 |   | $ | 0.01 |   |   | $ | — |   |   |
| Second Quarter |       | $          | 0.05       |       | $          | 0.03 |   |   | $ | — |   |   | $ | 0.05 |   | $ | 0.01 |   |   | $ | — |   |   |
| Third Quarter  |       | $          | 0.04       |       | $          | 0.02 |   |   | $ | — |   |   | $ | 0.05 |   | $ | 0.02 |   |   | $ | — |   |   |
| Fourth Quarter |       | $          | 0.04       |       | $          | 0.02 |   |   | $ | — |   |   | $ | 0.03 |   | $ | 0.01 |   |   | $ | — |   |   |

 

At March 28, 2005,the 71,980,216 units outstanding were held by 12,005 unitholders of record.

**Item 6.**                        SelectedFinancial Data.
| ** **                          | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| Royalty income                      |       | $        | —     |     | $          | —   |       | $        | —     |     | $          | 1,772,595 |   | $ | 3,909,836 |   |
| Distributable  income               |       | $        | —     |     | $          | —   |       | $        | —     |     | $          | 1,401,106 |   | $ | 3,586,711 |   |
| Distributable  income per unit      |       | $        | —     |     | $          | —   |       | $        | —     |     | $          | 0.0195 |   | $ | 0.0498 |   |
| Accumulated  deficit at year end(1) |       | $        | (59,035    | )        | $          | (696,712 | )          | $        | (825,616   | )        | $          | (81,329 | ) | $ | — |   |
| Total assets at year  end.          |       | $        | 387,976    |     | $          | 951,557  |       | $        | 1,497,883  |     | $          | 2,153,070 |   | $ | 3,463,972 |   |

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(1)          The deficit has beenrecouped in the first quarter of 2005.

23

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**Item 7.**                        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.

**Critical AccountingPolicies**

The financialstatements of the Trust are prepared on the following basis:

(a)   Royaltyincome recorded for a month is the Trust’s interest in the amount computed andpaid by the working interest owner to the Partnership for such month ratherthan either the value of a portion of the oil and gas sold by the workinginterest owner for such month or the amount subsequently determined to be 90%of the net proceeds for such month;

(b)   Interestincome, interest receivable and distributions payable to unitholders includeinterest to be earned on short-term investments from the financial statementdate through the next date of distribution; and

(c)   Trustgeneral and administrative expenses are recorded in the month they accrue andare recoupable from Royalty income.

This basis for reporting distributable income isconsidered to be the most meaningful because distributions to the unitholdersfor a month are based on net cash receipts for such month. However, it willdiffer from the basis used for financial statements prepared in accordance withaccounting principles generally accepted in the United States of Americabecause, under such accounting principles, royalty income for a month would bebased on net proceeds from sales for such month without regard to whencalculated or received and interest income for a month would be calculated onlythrough the end of such month.

As discussed in Note 1 tothe financial statements, effective after December 31, 2004 the Trustee iscontractually required to liquidate the Trust within a two year period. As aresult, during the first quarter of 2005, the Trust changed its basis foraccounting periods subsequent to December 31, 2004 from the going concernbasis to the liquidation basis. Accordingly, the carrying value of theremaining assets will be presented at their estimated realizable values and allliabilities will be presented at estimated settlement amounts.

**Status of 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. As a result ofcontinued declines in production on Royalty Properties nearing the end of theirestimated productive lives, Royalty income received by the Trust in 2002, 2003and 2004 fell below the Termination Threshold prescribed by the TrustIndenture. In addition, there was an accumulated deficit due PNR as of December 31,2004 of $59,035 that will be deducted from any future gross proceeds on the RoyaltyProperties, which deduction will reduce future Royalty income.

The Trustee, which has no authority or discretionarycontrol over the timing of expenditures, production or income on the RoyaltyProperties, has no discretion regarding the occurrence of the TerminationThreshold or its consequences.

The Trust Indenture provides the Trustee a two-yearperiod during which it must sell all of the Trust properties. The TrustIndenture provides that such properties must be sold for cash and not for anyother consideration. The Trustee expects that the sale process will be open toany persons desiring to participate, but, as is customary, access toinformation and participation may be limited to persons who executeconfidentiality agreements regarding information provided by the workinginterest owners. The Trustee 

24

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may also require biddersto identify themselves clearly and to represent or evidence sufficientfinancing in order to participate, as the Trustee expects payment will berequired promptly after the close of bidding without any financing conditions. Accordingly,the auction may not be a “public” auction in the sense that it may not be opento anyone who does not satisfy these requirements. The Trustee is currentlyreviewing a potential online bidding process for participants in order toprovide current public information on bidding to the marketplace. The Trusteewill also determine a duration of bidding that it deems in the best interest ofthe unitholders.

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

The Trustee currently expects to commence the saleprocess in the latter half of 2005, after its receipt of additional oil and gasreserve information for the production test on the Brazos A-39 exploratoryprospect and the completion of the joint venture audit referred to above. TheTrustee is waiting for this information to ensure as much information aspossible regarding the Royalty Properties is available for bidders inconnection with a sale.

Below is additionalinformation regarding the Trust properties provided by PNR:

*Properties producing as of December 31, 2004*
| **Property**           | ** ** | ** ** | ** ** | **Number of  Producing  wells(1)** | ** ** | **Estimated  Productive  Life(1)** | ** ** | **Estimated  Future  Royalty  Income(2)** | ** ** |
|------------------------|------------|------------|------------|-----------------------------------------|------------|------------------------------------|------------|-------------------------------------------|------------|
| West Delta No. 61 |       |       | 4          |                                    |       |                               | 7 years    |                                      |       | $ | 1,733,706 |   |
| Brazos A-39            |       |       | —     |                                    |       |                               | None       |                                      |       | (205,200 | ) |
| Brazos A-7             |       |       | 1          |                                    |       |                               | 1 year     |                                      |       | (189,960 | ) |
|                        |            |            |            |                                         |            |                                    |            |                                           |            |  |  |  |  |  |

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(1)          Information obtainedfrom December 31, 2004 reserve report prepared by PNR.

(2)          Representsestimated future royalty income from the December 31, 2004, reserve reportwithout considering the recoupment by PNR of the accumulated deficit of$59,035. Future royalty income was calculated using oil and gas spot prices ineffect at December 31, 2004 of $43.33 per barrel and $6.19 per Mcf.Estimated future net cash outlays on Brazos A-39 and Brazos A-7represent operating expenses that are required to be incurred until abandonmentprocedures are commenced.

*Properties abandoned or scheduled for abandonment asof December 31, 2004*
| **Property**           | ** ** | ** **                                                   | ** ** | **Status** |
|------------------------|------------|--------------------------------------------------------------|------------|------------|
| Brazos A-7             |       | Abandonment in 2005 (excluding producing well and  platform) |
| Brazos A-39            |       | Abandonment in 2005 (excluding Midway prospect)*             |
| West Delta 62          |       | Plug and abandonment procedures completed in 2003            |
| South Marsh Island 155 |       | Plug and abandonment procedures completed in 2002            |
| South Marsh Island 156 |       | Plug and abandonment procedures completed in 2002            |
| Vermillion 381         |       | Plug and abandonment procedures completed in 1989            |
| South Pelto 12         |       | Plug and abandonment procedures completed in 1986            |
| Matagorda Island 624   |       | Plug and abandonment procedures completed in 2003            |
| High Island 567        |       | Plug  and abandonment procedures completed in 1992           |

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*       Midwayprospect will be tied-back to an existing platform operated by a third party.

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**Financial and OperationalReview**

As discussed in Item 1 of this Form 10-K, PNR hasadvised the Trust that during 2004, its offshore gas production was marketedunder short-term contracts at spot market prices primarily to OccidentalPetroleum Corp. and Total S.A. and that it expects to continue to market itsproduction under short-term contracts for the foreseeable future. Spot marketprices for natural gas were on the average higher in 2004 than spot marketprices in 2003.

The amount of cash distributed by the Trust is dependenton, among other things, the sales prices and quantities of gas, crude oil,condensate and natural gas liquids produced from the Royalty Properties and thequantities sold. Substantial uncertainties exist with regard to future gas andoil prices, which are subject to fluctuations due to the regional supply anddemand for natural gas and oil, production levels and other activities of theOrganization of the Petroleum Exporting Countries (“OPEC”) and other oil andgas producers, weather, storage levels, industrial growth, conservationmeasures, competition and other variables.

Belowis a summary of Royalty income received on the Trust properties for each of thethree years ending December 31, 2004:
| ** **                           | ** ** | **2004** | ** ** | **2003** | ** ** | **2002**   | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|------------|------------|
| Gross proceeds @  90%                |       | $        | 810,336    |     | $          | 745,192    |       | $ | 848,698 |   |
| Operating  expenditures @ 90%        |       | (172,594 | )          | (605,927 | )          | (1,232,483 | )          |
| Capital  expenditures @ 90%(1)       |       | —   |       | (10,348  | )          | (360,576   | )          |
| Net proceeds  (deficit)              |       | 637,742  |       | 128,917  |       | 744,361    | )          |
| Increase  (decrease) in deficit      |       | (637,742 | )          | (128,917 | )          | 744,361    |       |
| Net proceeds  after deficit recovery |       | —   |       | —   |       | —     |       |
| Royalty income (99.99%)              |       | $        | —     |     | $          | —     |       | $ | — |   |

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(1)          PNR believes that thefuture abandonments have been fully funded, no such amounts were withheld in2003 or 2004.

Belowis a summary of distributable income for the years ended December 31,2004, 2003 and 2002:
| ** **                              | ** ** | **Years Ended December 31,** | ** ** |
|-----------------------------------------|------------|---------------------------------------------|------------|
| ** **                              | ** ** | **2004**                                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| Royalty income                          |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Interest income                         |       | 4,493                                       |       | 9,169 |   | 22,100 |   |
| General and  administrative expenses    |       | (4,493                                      | )          | (9,169 | ) | (22,100 | ) |
| Distributable  income                   |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Distributable  income per unit          |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Accumulated deficit (as  of period end) |       | $                                           | (59,035    | ) | $ | (696,712 | ) | $ | (825,616 | ) |

 

There was no Royalty income during 2004, 2003 and2002. 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 the productive lives. See “—Operational Review” below.

26

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Below is an operational review of the remainingproducing Trust properties:

***Brazos A-7 and A-39***
| ** **                    | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Gross proceeds @  90%         |       | $        | 160,014    |     | $          | 193,039  |       | $ | 515,950 |   |
| Operating  expenditures @ 90% |       | (171,043 | )          | (429,232 | )          | (667,482 | )          |
| Capital  expenditures @ 90%   |       | —   |       | 2,481    |       | (26,483  | )          |
| Net proceeds (deficit)        |       | $        | (11,029    | )        | $          | (233,712 | )          | $ | (178,015 | ) |

 

The Brazos A-7 and A-39blocks continued to experience a decrease in natural gas production due tonatural production decline. As of December 31, 2004, these two blocks hadone well producing, the Brazos A-7 No. B-1 well. The Brazos A-39No. A-3 well ceased production during the fourth quarter of 2003. PNRfarmed out the Trust’s interest in both of these blocks so that two explorationprospects could be drilled and in which the Trust will retain an overridingroyalty interest. The first prospect on Brazos A-7 was drilled during 2003and was determined to be a dry hole. As such, the well was plugged andabandoned. Drilling commenced on the exploratory prospect on Brazos A-39 in September 2003and testing was still being done at December 31, 2004. The production testwas completed during the first quarter of 2005. PNR, the operator on thisproperty, has informed the Trustee that the lower horizon of the prospect wasdetermined to be non-commercial, while the middle horizon produced at 10million cubic feet of gas per day during a seventeen hour flow test. There isno assurance that these flow rates will continue, as offshore oil and gasproperties often experience stronger initial flow rates and more rapid declinesthan onshore properties. PNR expects to tie-back this prospect into an existingplatform, operated by a third party, with first production expected to commenceby the fourth quarter of 2005. As of December 31, 2004, no proved oil andgas reserves had been attributable to this prospect, however, as a result ofthe successful production test, PNR is currently evaluating the quantity ofproved reserves to be assigned.

***West Delta 61 and62***
| ** **                    | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Gross proceeds @  90%         |       | $        | 650,322    |     | $          | 552,153  |       | $ | 146,460 |   |
| Operating  expenditures @ 90% |       | (1,551   | )          | (176,695 | )          | (394,328 | )          |
| Capital  expenditures @ 90%   |       | —   |       | (12,829  | )          | —   |       |
| Net proceeds (deficit)        |       | $        | 648,771    |     | $          | 362,629  |       | $ | (247,868 | ) |

 

The West Delta 61 and 62blocks experienced an increase in oil and natural gas production during 2004due to Stone bringing their wells back on production after being shut in to bere-routed to a new platform for production handling in 2003 and the newexploratory well that was placed on production in the third quarter of 2004.The PNR-operated wells ceased production in 2002, and the wells were pluggedand abandoned by year-end with the facilities being completely abandoned during2003. In 2002, on West Delta 62, the Trust received royalty income fromone producing well pursuant to a farm out agreement with Walter Oil and GasCorporation (“Walter”). Production from this well also ceased in 2002 andWalter completed plugging and abandonment procedures and relinquished thelease. The only remaining wells on this block are in West Delta 61. PNR farmedout a portion of West Delta 61 to Stone retaining a 12.5% (11.25% net to the Trust)overriding royalty interest. Stone has four producing wells on this property.

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*Other Properties*

The Matagorda Island 624 block, operated by PNR,ceased production in the second quarter of 2002. PNR attempted a workover inthe third quarter of 2002, but was unsuccessful. In the first quarter of 2003,PNR plugged and abandoned the wells, and in July 2003, the platform wasremoved.

The South Marsh Island 155and 156 blocks ceased production during the first quarter 2000. The abandonmentprocedures were completed and the lease was relinquished during 2002.

*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*

Thebelow table provides a rollforward of the abandonment and removal costs cashreserve that PNR has withheld from the Trust since January 1, 2003:
| Balance,  January 1, 2003                             |   | $          | 5,640,443 |   |
|------------------------------------------------------------|--------|------------|-----------|--------|
| Abandonment cost  incurred (Mat. Is. 624 & WD 62) |   | (2,839,800 | )         |
| Balance,  December 31, 2003                           |   | 2,800,643  |      |
| Abandonment cost  incurred (Mat. Is. 624 & WD 62) |   | (124,492   | )         |
| Balance,  December 31, 2004                           |   | $          | 2,676,151 |   |

 

**Liquidity andCapital Resources**

In accordance with the provisions of the Trustconveyance, generally all revenues received by the Trust, net of Trustadministrative expenses and any cash reserves established for the payment ofcontingent or future obligations of the Trust, are distributed currently to theunitholders.

The Trust’s source of cashis the Royalty income received from its share of the net proceeds from theRoyalty Properties. Reference is made to Note 6 in the Notes to FinancialStatements under Item 8 of this Form 10-K for estimates of future Royaltyincome attributable to the Partnership, of which the Trust has a 99.99%interest.

28

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**NET PROCEEDS, PRODUCTION AND AVERAGE PRICES(Unaudited)**
| ** **                                             | ** ** | ** Brazos  A-7 and A-39 ** | ** ** | **West  Delta  61 and 62** | ** ** | **Matagorda  Island 624** | ** ** | **South Marsh  Island 155  and 156** | ** ** | **Total** | ** ** |
|--------------------------------------------------------|------------|------------------------------------------------|------------|--------------------------------------|------------|--------------------------------|------------|-----------------------------------------------------|------------|-----------|------------|
| **Year Ended December 31, 2004:**                 |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   |   |   |
| 90% of—Gross  proceeds                            |       |                                           | $          | 160,014                              |       |                           | $          | 650,322                                             |       | $         | —     |   |   | $ | — |   |   | $ | 810,336 |   |
| Less 90% of—Operating  costs                      |       |                                           | (171,043   | )                                    |       | (1,551                         | )          | —                                              |       |      | —     |   |   | (172,594 | ) |
| Capital costs  recovered                               |       |                                           | —     |                                 |       | —                         |       | —                                              |       |      | —     |   |   | — |   |
| Net Proceeds                                           |       |                                           | $          | (11,029                              | )          |                           | $          | 648,771                                             |       | $         | —     |   |   | $ | — |   |   | $ | 637,742 |   |
| Trust share of net  proceeds (99.99%).                 |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | $ | 637,678 |   |
| Recoupment of  deficit                                 |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | (637,678 | ) |
| Royalty income                                         |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | — |   |
| Trust Deficit                                          |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | $ | (59,035 | ) |
| 90% of Production Volumes  and Average Sales Prices:   |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   |   |   |
| Crude oil,  condensate and natural gas liquids (Bbls)  |       |                                           | 36         |                                 |       | 9,596                          |       | —                                              |       |      | —     |   |   | 9,632 |   |
| Average sales  price per Bbl                           |       |                                           | $          | 35.78                                |       |                           | $          | 32.55                                               |       | $         | —     |   |   | $ | — |   |   | $ | 32.57 |   |
| Natural gas (Mcf)                                      |       |                                           | 29,145     |                                 |       | 63,109                         |       | —                                              |       |      | —     |   |   | 92,254 |   |
| Average sales  price per Mcf                           |       |                                           | $          | 5.45                                 |       |                           | $          | 5.35                                                |       | $         | —     |   |   | $ | — |   |   | $ | 5.38 |   |
| Producing wells  (gross)                               |       |                                           | 1          |                                 |       | 4                              |       | —                                              |       |      | —     |   |   | 5 |   |
| **Year Ended December 31, 2003:**                 |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   |   |   |
| 90% of—Gross  proceeds                            |       |                                           | $          | 193,039                              |       |                           | $          | 552,153                                             |       | $         | —     |   |   | $ | — |   |   | $ | 745,192 |   |
| Less 90% of—Operating  costs                      |       |                                           | (429,232   | )                                    |       | (176,695                       | )          | —                                              |       |      | —     |   |   | (605,927 | ) |
| Capital costs  recovered                               |       |                                           | 2,481      |                                 |       | (12,829                        | )          | —                                              |       |      | —     |   |   | (10,348 | ) |
| Net Proceeds                                           |       |                                           | $          | (233,712                             | )          |                           | $          | 362,629                                             |       | $         | —     |   |   | $ | — |   |   | $ | 128,917 |   |
| Trust share of net  proceeds (99.99%)                  |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | $ | 128,904 |   |
| Recoupment of  deficit                                 |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | (128,904 | ) |
| Royalty income                                         |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | — |   |
| Trust Deficit                                          |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | $ | (696,712 | ) |
| 90% of Production Volumes and Average Sales Prices:    |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   |   |   |
| Crude oil,  condensate and natural gas  liquids (Bbls) |       |                                           | 348        |                                 |       | 7,266                          |       | —                                              |       |      | —     |   |   | 7,614 |   |
| Average sales  price per Bbl                           |       |                                           | $          | 27.42                                |       |                           | $          | 27.92                                               |       | $         | —     |   |   | $ | — |   |   | $ | 27.90 |   |
| Natural gas (Mcf)                                      |       |                                           | 35,644     |                                 |       | 52,401                         |       | —                                              |       |      | —     |   |   | 88,045 |   |
| Average sales  price per Mcf                           |       |                                           | $          | 5.15                                 |       |                           | $          | 7.26                                                |       | $         | —     |   |   | $ | — |   |   | $ | 6.05 |   |
| Producing wells  (gross)                               |       |                                           | 1          |                                 |       | 3                              |       | —                                              |       |      | —     |   |   | 4 |   |
| **Year Ended December 31, 2002:**                 |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   |   |   |
| 90% of—Gross  proceeds                            |       |                                           | $          | 515,950                              |       |                           | $          | 146,460                                             |       | $         | 186,288    |   |   | $ | — |   |   | $ | 848,698 |   |
| Less 90% of—Operating  costs                      |       |                                           | (667,482   | )                                    |       | (394,328                       | )          | (170,673                                            | )          |      | —     |   |   | (1,232,483 | ) |
| Capital costs  recovered                               |       |                                           | (26,483    | )                                    |       | —                         |       | (259,524                                            | )          |      | (74,569    | ) |   | (360,576 | ) |
| Net Proceeds                                           |       |                                           | $          | (178,015                             | )          |                           | $          | (247,868                                            | )          | $         | (243,909   | ) |   | $ | (74,569 | ) |   | $ | (744,361 | ) |
| Trust share of net  proceeds (99.99%)                  |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | $ | (744,287 | ) |
| Increase in  deficit                                   |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | 744,287 |   |
| Royalty income                                         |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | — |   |
| Trust Deficit                                          |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   | $ | (825,616 | ) |
| 90% of Production Volumes and Average Sales Prices:    |       |                                           |       |                                 |       |                           |       |                                                |       |      |       |   |   |   |   |
| Crude oil,  condensate and natural gas  liquids (Bbls) |       |                                           | 434        |                                 |       | 3,566                          |       | 850                                                 |       |      | —     |   |   | 4,850 |   |
| Average sales  price per Bbl                           |       |                                           | $          | 20.03                                |       |                           | $          | 21.46                                               |       | $         | 20.45      |   |   | — |   |   | $ | 21.15 |   |
| Natural gas (Mcf)                                      |       |                                           | 204,222    |                                 |       | 24,918                         |       | 70,687                                              |       |      | —     |   |   | 299,827 |   |
| Average sales  price per Mcf                           |       |                                           | $          | 2.48                                 |       |                           | $          | 2.81                                                |       | $         | 2.39       |   |   | — |   |   | $ | 2.49 |   |
| Producing wells  (gross)                               |       |                                           | 2          |                                 |       | 3                              |       | —                                              |       |      | —     |   |   | 5 |   |

 

29

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·       Theamounts shown are for the Mesa Offshore Royalty Partnership.

·       Producingwells indicates the gross number of wells capable of production as of the endof the period.

·       Grossproceeds is based on actual production for a twelve-month period endingon October 31 of each year, respectively.

·       Capitalcosts recovered represent capital costs incurred during the current or priorperiod to the extent that such costs have been recovered by PNR from grossproceeds.

·       TheTrust deficit balance of $59,035 as of December 31, 2004 will be deductedfrom any future gross proceeds on the Royalty properties, which deduction willreduce future Royalty income.

*Production andPrice Review*

Production volumes for natural gas increased to 92,254Mcf in 2004 compared to 88,045 Mcf in 2003 primarily due to increasedproduction at West Delta 61 and 62 due to the Stone wells coming back on-lineand the new exploratory well that was placed on production in the third quarterof 2004. This was partially offset by natural production decline at Brazos A-7and A-39. The average sales price received for natural gas in 2004 was $5.38per Mcf compared with $6.05 per Mcf in 2003. Crude oil, condensate and naturalgas liquids production volumes increased to 9,632 barrels in 2004 as comparedto 7,614 barrels in 2003. This increase was also the result of the increasedproduction at West Delta 61 and 62 due to the Stone wells coming back on-lineand the new exploratory well that was placed on production in the third quarterof 2004, partially offset by the natural production decline at the Brazos A-7and A-39 properties. The average sales price in 2004 for crude oil, condensateand natural gas liquids was  $32.57 perbarrel as compared with $27.90 per barrel in 2003.

Production volumes fornatural gas decreased to 88,045 Mcf in 2003 compared with 299,827 Mcf in 2002primarily due to natural production decline at Brazos A-7 and A-39 andMatagorda Island 624, partially offset by increased production at West Delta 61and 62 due to the Stone wells coming back on-line. The average sales pricereceived for natural gas in 2003 was $6.05 per Mcf compared with $2.49 per Mcfin 2002. Crude oil, condensate and natural gas liquids production volumesincreased to 7,614 barrels in 2003 as compared to 4,850 barrels in 2002. Thisincrease was also the result of the increased production at West Delta 61 and62 due to the Stone wells coming back on-line, partially offset by the naturalproduction decline at the Brazos A-7 and A-39 and Matagorda Island 624properties. The average sales price in 2003 for crude oil, condensate andnatural gas liquids was $27.90 per barrel as compared with $21.15 per barrel in2002.

**Item 7A.**                Quantitative andQualitative Disclosures About Market Risk.

Not applicable.

30

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**Item 8.**                        FinancialStatements and Supplementary Data.

**MESAOFFSHORE TRUSTSTATEMENTS OF DISTRIBUTABLE INCOME**
| ** **                           | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------|------------|---------------------------------------------|------------|
| ** **                           | ** ** | **2004**                                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| Royalty income                       |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Interest income                      |       | 4,493                                       |       | 9,169 |   | 22,100 |   |
| General and  administrative expenses |       | (4,493                                      | )          | (9,169 | ) | (22,100 | ) |
| Distributable  income                |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Distributable  income per unit       |       | $                                           | —     |   | $ | — |   | $ | — |   |

 

**STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS**
| ** **                                                                         | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                         | ** ** | **2004**              | ** ** | **2003** | ** ** |
| ASSETS                                                                             |       |                  |       |   |   |
| Cash and short-term  investments                                                   |       | $                     | 376,599    |   | $ | 938,827 |   |
| Interest  receivable                                                               |       | 250                   |       | 1,603 |   |
| Net overriding  royalty interest in oil and gas properties                         |       | 380,905,000           |       | 380,905,000 |   |
| Less: accumulated amortization                                                     |       | (380,893,873          | )          | (380,893,873 | ) |
| Total assets                                                                       |       | $                     | 387,976    |   | $ | 951,557 |   |
| LIABILITIES AND  TRUST CORPUS                                                      |       |                  |       |   |   |
| Reserve for trust  expenses                                                        |       | $                     | 376,849    |   | $ | 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                                                |       | $                     | 387,976    |   | $ | 951,557 |   |

 

**STATEMENTS OF CHANGES IN TRUST CORPUS**
| ** **                                      | ** ** | **Years Ended December 31,** | ** ** |
|-------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                      | ** ** | **2004**                                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| Trust corpus,  beginning of year                |       | $                                           | 11,127     |   | $ | 11,127 |   | $ | 11,127 |   |
| Distributable income                            |       | —                                      |       | — |   | — |   |
| Distributions to unitholders                    |       | —                                      |       | — |   | — |   |
| Amortization of net overriding royalty interest |       | —                                      |       | — |   | — |   |
| Trust corpus, end of  year                      |       | $                                           | 11,127     |   | $ | 11,127 |   | $ | 11,127 |   |

 

The accompanying notes are an integral part of these financialstatements.

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**MESA OFFSHORE TRUSTNOTES TO FINANCIAL STATEMENTS**

**(1)   TrustOrganization and Provisions**

*The Trust*

The Mesa Offshore Trust (the “Trust”) was createdeffective December 1, 1982. On that date, Mesa Petroleum Co., predecessorto Mesa Limited Partnership, which was predecessor to MESA Inc.,transferred to the Trust a 99.99% interest in the Mesa Offshore RoyaltyPartnership (the “Partnership”). The Trust is an independent trust administeredby JPMorgan Chase Bank, N.A., as trustee (the “Trustee”). JPMorgan Chase Bank,N.A., was formerly known as The Chase Manhattan Bank and is the successor bymergers to the original name of the Trustee, Texas Commerce Bank NationalAssociation.

The terms of theMesa Offshore Trust Indenture (the “Trust Indenture”) provide, among otherthings, that:

(a)   the Trustcannot engage in any business or investment activity or purchase any assets;

(b)   theinterest in the Partnership can be sold in part or in total for cash uponapproval of the unitholders;

(c)   the Trusteecan establish cash reserves and borrow funds to pay liabilities of the Trustand can pledge the assets of the Trust to secure payment of the borrowings;

(d)   the Trusteewill make cash distributions to the unitholders in January, April, July andOctober of each year as discussed more fully in Note 4; and

(e)   the Trust will terminate upon the first to occur of the followingevents: (i) the total amount of cash received per year by the Trust foreach of three successive years commencing after December 31, 1987 is lessthan ten times one-third of the total amount payable to the Trustee ascompensation for such three-year period (the “Termination Threshold”) or (ii) avote by holders of a majority of the outstanding units in favor of termination.Amounts earned by the Trustee as compensation were approximately $148,000,$152,000 and $84,000 for the years 2004, 2003 and 2002, respectively. Asdescribed further in “Termination of the Trust” on page 8 of this Form 10K,the Termination Threshold was met in the three consecutive years ending December 31,2004. Upon termination of the Trust, the Trustee will sell for cash all theassets held in the Trust estate and make a final distribution to unitholders ofany funds remaining after all Trust liabilities have been satisfied.

*The Partnership*

The Partnership was created to receive and hold a netoverriding royalty interest (the “Royalty”) in ten producing and nonproducingoil and gas properties located in federal waters offshore Louisiana and Texas(the “Royalty Properties”). MESA Inc. created the Royalty out of itsworking interest in the Royalty Properties and transferred it to thePartnership. Until August 7, 1997, MESA Inc. owned and operated itsassets through Mesa Operating Co. (“Mesa”), the operator and the managinggeneral 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”). Subsequentto the Merger, Pioneer owns and operates its assets through PNR and is also themanaging general partner of the Partnership.

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The Partnership is owned99.99% by the Trust and 0.01% by PNR. PNR serves as the managing generalpartner of the Partnership. PNR receives no compensation for serving asmanaging general partner other than the income it receives attributable to itsinterest in the Partnership.

*Status of the Trust*

The Trust Indentureprovides that the Trust will terminate if the total amount of cash per yearreceived by the Trust falls below certain levels for each of three successiveyears (the “Termination Threshold”). **As aresult of continued declines in production on Royalty Properties nearing theend of their estimated productive lives, Royalty income received by the Trustin 2002, 2003 and 2004 fell below the Termination Threshold prescribed by theTrust Indenture, resulting in the contractual termination of the Trusteffective after December 31, 2004.**The Trustee, which has noauthority or discretionary control over the timing of expenditures, productionor income on the Royalty Properties, has no discretion regarding the occurrenceof the Termination Threshold or its consequences.

The Trust Indentureprovides the Trustee a two-year period during which it must sell all of theTrust properties. The Trust Indenture provides that such properties must besold for cash and not for any other consideration. The Trustee expects that thesale process will be open to any persons desiring to participate, but, as iscustomary, access to information and participation may be limited to personswho execute confidentiality agreements regarding information provided by theworking interest owners. The Trustee may also require bidders to identifythemselves clearly and to represent or evidence sufficient financing in orderto participate, as the Trustee expects payment will be required promptly afterthe close of bidding without any financing conditions. Accordingly, the auctionmay not be a “public” auction in the sense that it may not be open to anyonewho does not satisfy these requirements. The Trustee is currently reviewing apotential online bidding process for participants in order to provide currentpublic information on bidding to the marketplace. The Trustee will alsodetermine a duration of bidding that it deems in the best interest of theunitholders.

The Trusteecurrently expects to commence the sale process in the latter half of 2005,after its receipt of additional oil and gas reserve information for theproduction test on the Brazos A-39 exploratory prospect and the completion ofthe joint venture audit being performed on the Trust’s properties. The Trusteeis waiting for this information to ensure as much information as possibleregarding the Royalty Properties is available for bidders in connection with asale.

**(2)**   Net Overriding Royalty Interest

The instruments conveying the Royalty to thePartnership provide that PNR will calculate and pay to the Partnership eachmonth an amount equal to 90% of aggregate net proceeds for the preceding month.Generally, net proceeds means the excess of the amounts received by PNR fromsales of its share of oil and gas from the Royalty Properties (gross proceeds)over the operating and capital costs incurred. Costs exceeding gross proceedsfor any month are recovered by PNR, with interest thereon at the prime rate ofthe Bank of America plus one-half percent, out of future gross proceeds priorto making further royalty payments to the Partnership.

Amortization of theRoyalty, which is calculated on the basis of current royalty income in relationto estimated future royalty income, is charged directly to trust corpus sincesuch amounts do not affect distributable income.

33

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**(3)**   Basis of Accounting

The financialstatements of the Trust are prepared on the following basis:

(a)   Royaltyincome recorded for a month is the Trust’s interest in the amount computed andpaid by the working interest owner to the Partnership for such month ratherthan either the value of a portion of the oil and gas produced by the workinginterest owner for such month or the amount subsequently determined to be 90%of the net proceeds for such month;

(b)   Interestincome, interest receivable and distributions payable to unitholders includeinterest to be earned on short-term investments from the financial statementdate through the next date of distribution; and

(c)   Trustgeneral and administrative expenses are recorded in the month they accrue andare recoupable from Royalty income.

This basis for reporting distributable income isconsidered to be the most meaningful because distributions to the unitholdersfor a month are based on net cash receipts for such month. However, it willdiffer from the basis used for financial statements prepared in accordance withaccounting principles generally accepted in the United States of Americabecause, under such accounting principles, royalty income for a month would bebased on net proceeds from production for such month without regard to whencalculated or received and interest income for a month would be calculated onlythrough the end of such month.

The instruments conveying the Royalty provide that theworking interest owner will calculate and pay the Partnership each month anamount equal to 90% of the net proceeds for the preceding month. Generally, netproceeds means the excess of the amounts received by the working interest ownerfrom sales of oil and gas from the Royalty Properties plus other cash receiptsover operating and capital costs incurred. For the twelve months ending December 2004,operating and capital costs incurred exceeded proceeds from oil and gas sales;accordingly, no Royalty income was reported.

There is a deficit balance due PNR as of December 31,2004 of $59,035 that will be deducted from any future gross proceeds on theRoyalty Properties, which deduction will reduce future Royalty income. Duringthe first quarter of 2005 the deficit balance was fully recouped. In addition,no Royalty income will be distributed to unitholders until the Trustee recoupsTrust expenses being paid from the reserve that the Trustee has established foranticipated future expenses. As of December 31, 2004, $1,623,151 will berecouped by the Trustee from future Royalty income before Trust distributionswill resume. The unexpended amount withheld by PNR for future abandonment costsat December 31, 2004 was $2,676,151.

As discussed in Note 1 tothe financial statements, effective after December 31, 2004 the Trustee iscontractually required to liquidate the Trust within a two year period. As aresult, during the first quarter of 2005, the Trust changed its basis foraccounting periods subsequent to December 31, 2004 from the going concernbasis to the liquidation basis. Accordingly the carrying value of the remainingassets will be presented at their estimated realizable values and allliabilities will be presented at estimated settlement amounts.

**(4)**   Distributions to Unitholders

Under the terms of theTrust Indenture, the Trustee must distribute to the unitholders all cashreceipts, after paying liabilities and providing for cash reserves asdetermined necessary by the Trustee. The amounts distributed are determined ona monthly basis and are payable to unitholders of record as of the lastbusiness day of each month. However, cash distributions are made quarterly inJanuary, April, July and October, and include interest earned from themonthly record dates to the dates of distribution.

34

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**(5)   FederalIncome Taxes**

The Trustee reports on the basis that the Trust is agrantor trust. Based on its previous audit policy, the Internal Revenue Service(the “IRS”) is expected to concur with such action. No IRS ruling has beenreceived or requested with respect to the Trust, however, and no court case hasbeen decided involving identical facts and circumstances. It is possible,therefore, that the IRS would assert upon audit that the Trust is taxable as acorporation and that a court might agree with such assertion.

As a grantor trust, theTrust will incur no federal income tax liability. In addition, it will incurlittle or no federal income tax liability if it is held to be a non-grantortrust. If the Trust were held to be taxable as a corporation, it would have topay tax on its net taxable income at the corporate rate.

**(6)**   Supplemental Reserve Information(Unaudited)

Estimates of the proved oil and gas reservesattributable to the Royalty as of December 31, 2004, 2003 and 2002 arebased on a report prepared by PNR. The estimates were prepared in accordancewith guidelines established by the Securities and Exchange Commission (the “SEC”).Accordingly, the estimates were based on existing economic and operatingconditions. The reserve volumes and revenue values contained in the reservereport for the Partnership interest were estimated by allocating to thePartnership a portion of the estimated combined net reserve volumes of theRoyalty Properties based on future net revenue. Production volumes are allocatedbased on royalty income. Because the net reserve volumes attributable to thePartnership interest are estimated using an allocation of reserve volumes basedon estimates of future net revenue, a change in prices or costs will result inchanges in the estimated net reserve volumes. Therefore, the estimated netreserve volumes attributable to the Partnership interest will vary if differentfuture price and cost assumptions are used. Only costs necessary to develop andproduce existing proved reserve volumes were assumed in the allocation ofreserve volumes to the Royalty.

Future prices for natural gas were based on prices ineffect as of each year end and existing contract terms. Prices being receivedas of each year end were used for sales of oil, condensate and natural gasliquids. Operating costs, production and ad valorem taxes and futuredevelopment and abandonment costs were based on current costs as of each yearend, with no escalation.

There are numerous uncertainties inherent inestimating the quantities and value of proved reserves and in projecting thefuture rates of production and timing of expenditures. The reserve data belowrepresent estimates only and should not be construed as being exact. Moreover,the discounted values should not be construed as representative of the currentmarket value of the Royalty. A market value determination would include manyadditional factors including: (i) anticipated future oil and gas prices; (ii) theeffect of federal income taxes, if any, on the future royalties; (iii) anallowance for return on investment; (iv) the effect of governmentallegislation; (v) the value of additional reserves, not considered provedat present, which may be recovered as a result of further exploration anddevelopment activities; and (vi) other business risks.

Estimates of reserve volumes attributable to theRoyalty are shown in order to comply with requirements of the SEC. There is noprecise method of allocating estimates of physical quantities of reservevolumes between PNR and the Partnership, since the Royalty is not a workinginterest and the Partnership does not own and is not entitled to receive anyspecific volume of reserves from the Royalty. The quantities of reservesattributable to the Partnership have been and will be affected by changes invarious economic factors utilized in estimating net revenues from the RoyaltyProperties, as well as any exploration activities which may be conducted byPNR. Therefore, the estimates of reserve volumes set forth below are to a largeextent hypothetical and differ in significant respects from estimates ofreserves attributable to a working interest.

35

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The future net revenues contained in the previouslymentioned reserve report have not been reduced for future general andadministrative expenses of the Trust, which are expected to approximate$500,000 annually. The general and administrative expenses of the Trust mayincrease in future years, depending on the amount of royalty income, increasesin accounting, engineering, legal, and other professional fees and otherfactors.

The following schedulesset forth (i) the estimated net quantities of proved and proved developedoil, condensate and natural gas liquids and natural gas reserves attributableto the Royalty, and (ii) the standardized measure of the discounted futureroyalty income attributable to the Royalty and the nature of changes in suchstandardized measure between years. These schedules are prepared on the accrualbasis, which is the basis on which PNR maintains its production records and isdifferent from the basis on which the Royalty is computed.

**EstimatedQuantities of Proved and Proved Developed Reserves (Unaudited)**
| ** **                                  | ** ** | **Oil and  Condensate** | ** ** | **Natural  Gas** | ** ** |
|---------------------------------------------|------------|------------------------------|------------|------------------|------------|
| ** **                                  | ** ** | **(Bbls)**                   | ** ** | **(Mcf)**        | ** ** |
| Proved Reserves:                            |       |                         |       |             |       |   |   |
| December 31, 2001                      |       |                         | 13,174     |             |       | 492,205 |   |
| Revisions of previous estimates             |       |                         | 3,487      |             |       | (59,763 | ) |
| Extensions, discoveries and other additions |       |                         | —     |             |       | — |   |
| Production                                  |       |                         | —     |             |       | — |   |
| December 31, 2002                      |       |                         | 16,661     |             |       | 432,442 |   |
| Revisions of previous estimates             |       |                         | (5,550     | )                |       | 237 |   |
| Extensions, discoveries and other additions |       |                         | —     |             |       | — |   |
| Production                                  |       |                         | —     |             |       | — |   |
| December 31, 2003                      |       |                         | 11,111     |             |       | 432,679 |   |
| Revisions of previous estimates             |       |                         | (5,151     | )                |       | (258,169 | ) |
| Extensions, discoveries and other additions |       |                         | —     |             |       | — |   |
| Production                                  |       |                         | —     |             |       | — |   |
| December 31, 2004                      |       |                         | 5,960      |             |       | 174,510 |   |
| Proved Developed  Reserves:                 |       |                         |       |             |       |   |   |
| December 31, 2001.                     |       |                         | 13,174     |             |       | 492,205 |   |
| December 31, 2002.                     |       |                         | 16,661     |             |       | 432,442 |   |
| December 31, 2003.                     |       |                         | 11,111     |             |       | 432,679 |   |
| December 31,  2004.                    |       |                         | 5,960      |             |       | 174,510 |   |

----

(See Notes on following page.)

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**StandardizedMeasure of Future Royalty Income fromProved Oil and Condensate and Gas Reserves, Discounted at 10% Per Annum(Unaudited)**
| ** **                                                                      | ** ** | **December 31,**   | ** ** |
|---------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                      | ** ** | **2004**                | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                      | ** ** | **(In thousands)** | ** ** |
| Ninety percent of  future gross proceeds                                        |       | $                       | 1,808      |   | $ | 3,584 |   | $ | 3,923 |   |
| Less ninety percent of—                                                    |       |                    |       |   |   |   |   |
| Future operating costs                                                          |       | (469                    | )          | (640 | ) | (1,406 | ) |
| Future capital costs, net of amounts previously  accrued                        |       | —                  |       | — |   | — |   |
| Deficit due PNR                                                                 |       | (59                     | )          | (697 | ) | (826 | ) |
| Future royalty  income                                                          |       | 1,280                   |       | 2,247 |   | 1,691 |   |
| Discount at 10%  per annum                                                      |       | (176                    | )          | (674 | ) | (21 | ) |
| Standardized measure of  future royalty income from proved oil and gas reserves |       | $                       | 1,104      |   | $ | 1,573 |   | $ | 1,670 |   |

 

**Changesin the Standardized Measure of Future Royalty Income fromProved Oil and Gas Reserves, Discounted at 10% Per Annum (Unaudited)**
| ** **                                  | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                  | ** ** | **2004**                                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                  | ** ** | **(In thousands)**                     | ** ** |
| Standardized  measure at beginning of year  |       | $                                           | 1,573      |   | $ | 1,670 |   | $ | 1,250 |   |
| Revisions of previous estimates             |       | (752                                        | )          | (675 | ) | (565 | ) |
| Net changes in prices and production costs  |       | 126                                         |       | 411 |   | 860 |   |
| Extensions, discoveries and other additions |       | —                                      |       | — |   | — |   |
| Royalty income                              |       | —                                      |       | — |   | — |   |
| Accretion of discount                       |       | 157                                         |       | 167 |   | 125 |   |
| Net changes in standardized measure         |       | (469                                        | )          | (97 | ) | 420 |   |
| Standardized measure at  end of year        |       | $                                           | 1,104      |   | $ | 1,573 |   | $ | 1,670 |   |

----

·       Theestimated quantities of proved reserves, standardized measure of future royaltyincome and changes in the standardized measure represent 100% of amounts forthe Partnership in which the Trust has a 99.99% interest.

**(7)**   SelectedQuarterly Financial Data (Unaudited)
| ** **                     | ** ** | **Summarized Quarterly Results** | ** ** |
|--------------------------------|------------|--------------------------------------------|------------|
| ** **                     | ** ** | **Three Months Ended**           | ** ** |
| ** **                     | ** ** | **March 31**                          | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| 2004:                          |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Royalty income                 |       |                                       | $          | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |
| Distributable  income          |       |                                       | $          | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |
| Distributable  income per unit |       |                                       | $          | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |
| 2003:                          |       |                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Royalty income                 |       |                                       | $          | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |
| Distributable  income          |       |                                       | $          | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |
| Distributable income per  unit |       |                                       | $          | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |

 

37

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**REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

JPMorgan Chase Bank, N.A.(Trustee)and the Unitholders of the Mesa Offshore Trust:

We have audited the accompanying statements of assets,liabilities, and trust corpus of Mesa Offshore Trust as of December 31,2004 and 2003, and the related statements of distributable income and changesin trust corpus for each of the years in the three-year period ended December 31,2004. These financial statements are the responsibility of the Trustee. Ourresponsibility is to express an opinion on these financial statements based onour audits.

We conducted our audits in accordance with auditingstandards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made by theTrustee, as well as evaluating the overall financial statement presentation. Webelieve that our audits provide a reasonable basis for our opinion.

These financial statements were prepared on the basisof accounting described in Note 3, which is a comprehensive basis ofaccounting other than accounting principles generally accepted in the UnitedStates of America.

In our opinion, the financial statements referred toabove present fairly, in all material respects, the assets, liabilities, andtrust corpus of Mesa Royalty Trust as of December 31, 2004 and 2003, andthe distributable income and changes in trust corpus for each of the years inthe three-year period ended December 31, 2004, in conformity with thebasis of accounting described in Note 3.

The accompanying financialstatements have been prepared assuming that the Trust will continue as a goingconcern. As discussed in Note 1 to the financial statements, as a result of continueddeclines in production on Royalty Properties nearing the end of their estimatedproductive lives, Royalty income received by the Trust during 2002, 2003 and2004 fell below the Termination Threshold prescribed by the Trust Indenture,resulting in the contractual termination of the Trust effective after December 31,2004. Accordingly, there exists substantial doubt about the Trust’s ability tocontinue as a going concern. The financial statements do not include anyadjustments that might result from the outcome of this uncertainty.

**KPMG LLP**
| Houston, Texas      |   |
|---------------------|--------|
| March 30, 2005 |   |

 

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**Item 9.**                        Changes inand Disagreements with Accountants on Accounting and Financial Disclosure.

None.

**Item 9A.**                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 andreported within the time periods specified in the SEC’s rules andregulations. Disclosure controls and procedures include controls and proceduresdesigned to ensure that information required to be disclosed by the Trust isaccumulated and communicated by Pioneer, as the managing general partner of thePartnership, and the working interest owners to JPMorgan Chase Bank, N.A., asTrustee of the Trust, and its employees who participate in the preparation ofthe Trust’s periodic reports as appropriate to allow timely decisions regardingrequired disclosure.

As of the date of this report, the Trustee carried outan evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich,as Trust Officer of the Trustee, has concluded that the controls and proceduresare effective, while noting certain limitations on disclosure controls andprocedures 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 potential weaknesses that are not subject to change ormodification by the Trustee or its employees. The contractual limitationscreating potential weaknesses in disclosure controls and procedures may bedeemed 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. While the Trustee requests material information for usein periodic reports as part of its disclosure controls and procedures, theTrustee does not control this information and relies entirely on the workinginterest owners to provide accurate and timely information when requested foruse 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 informationregarding the Royalty Properties from the working interest owners. While theTrustee requests material information for use in periodic reports as part ofits disclosure 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, and in factrelies, on certain experts in good faith. While the Trustee has no reason tobelieve its reliance upon experts is unreasonable, this reliance on experts andlimited access to information may be viewed as a weakness.

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

*Changes in Internal Controls.  *Tothe knowledge of the Trustee, there have been no significant changes in theTrustee’s internal controls or in other factors that could significantly affectthe Trustee’s internal controls subsequent to the date the Trustee completedits evaluation. The Trustee notes for purposes of clarification that it has noauthority over, and makes no statement concerning, the internal controls of theworking interest owners or the managing general partner of the Partnership.

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**PART III**

**Item 10.**                 Directors andExecutive Officers of the Registrant.

There are no directors or executive officers of theRegistrant. The Trustee is a corporate trustee that may be removed by theaffirmative vote of a majority of the units then outstanding at a meeting ofthe holders of units of beneficial interest of the Trust at which a quorum ispresent.

The Trust does not have a principal executive officer,principal financial officer, principal accounting officer or controller and,therefore, has not adopted a code of ethics applicable to such persons.However, employees of the Trustee must comply with the bank’s code of ethics.

The Trust does not have aboard of directors, and therefore does not have an audit committee, an auditcommittee financial expert or a nominating committee.

**Item 11.**                 ExecutiveCompensation.

Not applicable.

**Item 12.**                 SecurityOwnership of Certain Beneficial Owners and Management.

*(a)**          SecurityOwnership of Certain Beneficial Owners.*
| **Title and Class of Voting Securities** | ** ** | ** **                                                                          | ** ** | **Name and Address of  Beneficial Ownership** | ** ** | **Amount and Nature of Beneficial  Ownership(1)** | ** ** | **Percent of Class** | ** ** |
|-------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|-----------------------------------------------------------------------|------------|--------------------------------|------------|
| Units of  Beneficial Interest                                     |       | MOSH Holding, L.P.  Nine Greenway Plaza  Suite 3040  Houston, Texas 77046 |       |                                                              | 7,332,887  | (2)(3)                                                                |       |                           | 10.2       | % |   |
|                                                                   |            |                                                                                     |            |                                                                   |            |                                                                       |            |                                |            |  |  |  |  |

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(1)          Under applicableregulations of the Securities and Exchange Commission, securities are deemed tobe “beneficially” owned by a person who directly or indirectly holds or sharesof voting power with respect thereto.

(2)          Based on informationcontained in the Form 4 filed on December 23, 2003 and Schedule 13D/Afiled on December 16, 2003. These units of beneficial interest of theIssuer (the “Units”) are owned directly by Mosh Holding, L.P., a Texaslimited partnership (“MOSHLP”). Mosh Holding I, L.L.C., a Texaslimited liability company (“MOSHLLC”) is the sole general partner of MOSHLP andhas sole investment discretion and voting authority with respect to the Units.Charles A. Sharman, Joseph F. Langston, Jr. and Timothy M.Roberson are the sole managers and members of MOSHLLC, in which capacity theymay be deemed to share voting control and dispositive power over the Units.

(3)          MOSHLLC and Messrs. Sharman,Langston and Roberson disclaim beneficial ownership of the reported Unitsexcept to the extent of their respective pecuniary interest therein.

*(b)**          SecurityOwnership of Management.* Not applicable.

*(c)**           Changes in Control.* Registrant knows ofno arrangement, including the pledge of securities of the Registrant, theoperation of which may at a subsequent date result in a change in control ofthe Registrant.

**Item 13.**                 CertainRelationships and Related Transactions.

Not Applicable.

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**Item 14.**                 PrincipalAccountant Fees and Services

The Trust does not have an audit committee. Anypre-approval and approval of all services performed by the principal auditor orany other professional services firms and related fees are granted by theTrustee.

Thefollowing table presents fees for professional audit services rendered by KPMGLLP for the audit of the Mesa Offshore Trust financial statements for 2004 and2003 and fees billed for other services rendered by KPMG LLP.
| ** **          | ** ** | **2004** | ** ** | **2003** | ** ** |
|---------------------|------------|----------|------------|----------|------------|
| Audit fees(1)       |       | $        | 90,000     |     | $          | 88,000 |   |
| Audit related  fees |       | —   |       | —   |       |
| Tax fees(2)         |       | 25,000   |       | 25,000   |       |
| All other fees      |       | —   |       | —   |       |
| Total fees          |       | $        | 115,000    |     | $          | 113,000 |   |

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(1)          Audit fees consist offees for the audit of the Mesa Offshore Trust financial statements andreimbursement for travel related expenses.

(2)          Tax fees consist of feesrelated to the Mesa Offshore Trust’s tax information for its unitholders paidin 2004 related to 2003 tax work.

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**PART IV**

**Item 15.**                  Exhibits,Financial Statement Schedules.

**(a)(1)   FinancialStatements**

Thefollowing financial statements are set forth under Part II, Item 8 of thisAnnual Report on Form 10-K on the pages indicated.
|                                                                        | ** ** | **Page in this  Form 10-K** |
|------------------------------------------------------------------------|------------|---------------------------------------|
| Statements  of Distributable Income                                    |       |                                  | 31 |   |
| Statements  of Assets, Liabilities and Trust Corpus                    |       |                                  | 31 |   |
| Statements  of Changes in Trust Corpus                                 |       |                                  | 31 |   |
| Notes  to Financial Statements                                         |       |                                  | 32 |   |
| Report of Independent Registered  Public Accounting Firm—KPMG LLP |       |                                  | 38 |   |

 

**(a)(2)   Schedules**

Scheduleshave been omitted because they are not required, not applicable or theinformation required has been included elsewhere herein.

**(a)(3)   Exhibits**

(JPMorganChase Bank, N.A., is successor by mergers to the original name of the Trustee,Texas Commerce Bank National Association)
|      | ** ** | ** **                                                                                                                                                                                                                                                                                                       | ** ** | **SEC File or  Registration  Number** | ** ** | **Exhibit  Number** |
|------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|---------------------|
| 4(a) |       | *Mesa Offshore Trust Indenture between Mesa  Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated  December 15, 1982                                                                                                                                                               |       | 2-79673                               |       |                | 10 | (gg) |
| 4(b) |       | *Overriding Royalty Conveyance between Mesa  Petroleum Co. and Mesa Offshore Royalty Partnership, dated December 15,  1982                                                                                                                                                                                  |       | 2-79673                               |       |                | 10 | (hh) |
| 4(c) |       | *Partnership Agreement between Mesa Offshore  Management Co. and Texas Commerce Bank National Association, as Trustee,  dated December 15, 1982                                                                                                                                                             |       | 2-79673                               |       |                | 10 | (ii) |
| 4(d) |       | *Amendment to Partnership Agreement between Mesa  Offshore Management Co., Texas Commerce Bank National Association, as  Trustee, and Mesa Operating Limited Partnership, dated December 27, 1985  (Exhibit 4(d) to Form 10-K for year ended  December 31, 1992 of Mesa Offshore Trust) |       | 1-8432                                |       |                | 4 | (d) |
| 4(e) |       | *Amendment to Partnership Agreement between Texas  Commerce Bank National Association, as Trustee, and Mesa Operating dated as  of January 5, 1994 (Exhibit 4(e) to Form 10-K for  year ended December 31, 1993 of Mesa Offshore Trust)                                                 |       | 1-8432                                |       |                | 4 | (e) |
| 31   |       | Certification furnished pursuant to Section 302  of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                          |       |                                  |       |                |   |   |
| 32   |       | Certification furnished pursuant to Section 906  of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                          |       |                                  |       |                |   |   |

 

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized.
|                     | MESA OFFSHORE TRUST |
|---------------------|---------------------|
|                | By                  | JPMORGAN CHASE BANK,  N.A., TRUSTEE |
|                | By:                 | /s/ MIKE ULRICH |
|                |                | Mike Ulrich |
|                |                | *Vice President & Trust Officer* |
| March 30, 2005 |                | * * |

 

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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**EXHIBITINDEX**
| EXHIBIT  NUMBER | ** ** | ** **                                                                                                                                                                                                                                                                                                       | ** ** | ** ** | ** ** | **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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*                    Previouslyfiled with the Securities and Exchange Commission and incorporated herein byreference.

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