**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

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**FORM 10-K**
| **(Mark One)**                                       |       |                                                                                                                    |
|------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------|
| **x**                                                | ** ** | **ANNUAL REPORT PURSUANT TO SECTION 13  OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**      |
| **FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005** |
| **o**                                                | ** ** | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT  OF 1934** |

 

**FORTHE TRANSITION PERIODFROM                TO**

**Commission file 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          |   | (I.R.S. Employer     |
| Incorporation or  Organization)           |   | 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 registered pursuant to Section 12(b) ofthe Act:

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

 

Securitiesregistered pursuant to Section 12(g) of the Act:

**Units of beneficial interest**

(Title of Class)

Indicate by check mark if the registrant is awell-known seasoned issuer, as defined in Rule 405 of the SecuritiesAct. Yes o  No x

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 orSection 15(d) of the Act. Yes o  No x

Indicate by check mark whether the registrant (1) hasfiled 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 past90 days. Yes x No o

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, andwill not be contained, to the best of registrant’s knowledge, in definitiveproxy or information statements incorporated by reference in Part III ofthis Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer. Seedefinition of “accelerated filer and large accelerated filer” in Rule 12b-2of the Exchange Act (Check one):

| Large accelerated  filer o |   | Accelerated filer o |   | Non-accelerated filer x |
|---------------------------------|--------|--------------------------|--------|------------------------------|

 

Indicate by check mark whether the registrant is ashell company (as defined in Rule 12b-2 of the Act). Yes £  Nox

The aggregate market value of 71,980,216 Units ofBeneficial Interest in Mesa Offshore Trust held by non-affiliates of theregistrant at the closing sales price on June 30, 2005, of $0.03 wasapproximately $2,159,000.

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

As of March 31, 2006, 71,980,216 Units ofBeneficial Interest were outstanding in Mesa Offshore Trust.

DOCUMENTS INCORPORATED BY REFERENCE: **None.**

 

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**TABLE OF CONTENTS**

|            | ** ** | ** **                                                                                  | ** ** | **Page** |
|------------|------------|---------------------------------------------------------------------------------------------|------------|----------|
|       |       | **PART I**                                                                             |       | 4        |
| Item 1.    |       | Business                                                                                    |       | 4        |
|       |       | Description of the Trust                                                                    |       | 4        |
|       |       | Description of the Units                                                                    |       | 6        |
|       |       | Legal  Proceedings and Status of the Trust                                                  |       | 8        |
|       |       | Timing of Liquidation                                                                       |       | 10       |
|       |       | Description of Royalty Properties                                                           |       | 12       |
|       |       | Contracts                                                                                   |       | 23       |
|       |       | Regulation and Prices                                                                       |       | 24       |
| Item 1A.   |       | Risk  Factors                                                                               |       | 26       |
| Item 1B.   |       | Unresolved Staff  Comments                                                                  |       | 30       |
| Item 2.    |       | Properties                                                                                  |       | 30       |
| Item  3.   |       | Legal  Proceedings                                                                          |       | 30       |
| Item 4.    |       | Submission of Matters to a Vote of Security Holders                                         |       | 31       |
|       |       | **PART II**                                                                            |       | 32       |
| Item 5.    |       | Market for the Registrant’s Common Equity and Related  Unitholder Matters              |       | 32       |
| Item 6.    |       | Selected Financial Data                                                                     |       | 32       |
| Item 7.    |       | Management’s Discussion and Analysis of Financial  Condition and Results of Operations |       | 33       |
| Item 7A.   |       | Quantitative and Qualitative Disclosures About Market  Risk                                 |       | 38       |
| Item 8.    |       | Financial Statements and Supplementary Data                                                 |       | 39       |
| Item 9.    |       | Changes in and Disagreements with Accountants on  Accounting and Financial Disclosure       |       | 50       |
| Item 9A.   |       | Controls and Procedures                                                                     |       | 50       |
|       |       | **PART III**                                                                           |       | 51       |
| Item 10.   |       | Directors and Executive Officers of the Registrant                                          |       | 51       |
| Item 11.   |       | Executive Compensation                                                                      |       | 51       |
| Item 12.   |       | Security Ownership of Certain Beneficial Owners and  Management                             |       | 51       |
| Item 13.   |       | Certain Relationships and Related Transactions                                              |       | 51       |
| Item 14.   |       | Principal Accounting Fees and Services                                                      |       | 52       |
|       |       | **PART IV**                                                                            |       | 52       |
| Item 15.   |       | Exhibits, Financial Statement Schedules                                                     |       | 52       |
| SIGNATURES |       | 54                                                                                          |

 

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**NoteRegarding Forward-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 (“PNR”)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 “Item 1A. Risk Factors.” All subsequent written and oral forward-lookingstatements attributable to the Trust or persons acting on its behalf areexpressly qualified in their entirety by the Cautionary Statements.

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**PART I**

**Item 1.**                        Business.

**DESCRIPTION OF THE TRUST**

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” or “Pioneer”)(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. As hereinafter used in thisreport, the term PNR generally refers to the operator of the RoyaltyProperties, unless otherwise indicated. See “Legal Proceedings and Status ofthe Trust” on page 8 of this Form 10-K and “Timing ofLiquidation” on page 10 of this Form 10-K for additional informationregarding 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 $204,000, $148,000, and $152,000,for the years 2005, 2004 and 2003, respectively. As described further in “Statusof the Trust” on page 8 of this Form 10-K, the 

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Termination Threshold wasmet in each of the three consecutive years ending December 31, 2005. Upontermination of the Trust, the Trustee will sell for cash all the assets held inthe Trust estate and make a final distribution to unitholders of any fundsremaining after all Trust liabilities have 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 12 of this Form 10-K. TheConveyance provides for a monthly computation of Net Proceeds. “Net Proceeds”means the excess of Gross Proceeds, as hereinafter defined, received by PNRduring a particular 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 there from. 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 23 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 there from.

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 noemployees. Administrative functions of 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, ofthe cash distributed by the Partnership to the Trust during such month, plusany other cash receipts of the Trust during such month (other than interestearned on the Monthly Distribution Amount for any other month), over theliabilities of the Trust paid during such month, and adjusted for changes madeby the Trustee during such month in any cash reserves established for thepayment of contingent or future obligations of the Trust. The MonthlyDistribution Amount for each month is payable to unitholders of record on themonthly record date (the “Monthly Record Date”), which is the close of businesson the last business day of such month, or such later date as the Trusteedetermines is required to comply with legal or stock exchange requirements.However, to reduce the administrative expenses of the Trust, the TrustIndenture provides that the Trustee does not distribute cash monthly, butrather, during January, April, July and October of each year,distributes to each person who was a unitholder of record on a Monthly RecordDate during one or more of the immediately preceding three months, the MonthlyDistribution Amount for the month or months that he was a unitholder of record,together with interest earned on such Monthly Distribution Amount from the MonthlyRecord Date to the payment date.

**Liability of Unitholders**

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 Tax Matters**

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 States federalincome 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.

**LEGAL PROCEEDINGS AND STATUS OF THE TRUST**

*HurricaneOperations Update*

HurricaneKatrina struck the Gulf of Mexico in August 2005. PNR notified the Trustthat it had received preliminary assessments regarding damages from HurricaneKatrina to the West Delta production facilities in which the Trust has aninterest. The operator of the West Delta properties has informed PNR that theWest Delta properties have been shut in since August 27, 2005 due todamage to the platform, the pipeline and the sales terminal. The operator hasnotified PNR that the pipeline has not been repaired and currently there is noestimate as to when the repairs will be completed. The operator does not havean estimate on when production at West Delta will resume.

*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 of continued declines in productionon Royalty Properties nearing the end of their estimated productive lives,Royalty income received by the Trust in 2002, 2003 and 2004 fell below theTermination Threshold prescribed by the Trust Indenture**. The Trusteehas taken steps to begin the process of liquidating the Trust. See “—Timing ofLiquidation” below in this Note. 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 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 

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consideration.The Trustee expects that the sale process will be open to any persons desiringto participate, but, as is customary, access to information and participationmay be limited to persons who execute confidentiality agreements regardinginformation provided by the working interest owners. The Trustee may alsorequire bidders to identify themselves clearly and to represent or evidencesufficient financing in order to participate, as the Trustee expects paymentwill be required promptly after the close of bidding without any financingconditions. Accordingly, the auction may not be a “public” auction in the sensethat it may not be open to anyone who does not satisfy these requirements. TheTrustee is currently reviewing a potential online bidding process forparticipants in order to provide current public information on bidding to themarketplace. The Trustee will also determine a duration of bidding that itdeems in the best interest of the Unitholders.

*Legal Proceedings*

On April 11, 2005, MOSH Holding, L.P. (MHLP)filed an Original Petition in the District Court of Travis County, Texas, 250thJudicial District, against Pioneer Natural Resources Company; Pioneer NaturalResources USA, Inc.; Woodside Energy (USA), Inc. (Woodside); andJPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (Case No. GN501113).On November 28, 2005, Plaintiff amended its petition. In the amendedpetition, MHLP asserts claims against Pioneer and Woodside for mattersincluding (1) a wrongful farmout of Brazos A-39 by Pioneer, (2) awrongful delay by Pioneer in producing Brazos A-39, (3) fraudulentaccounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aidingand abetting breach of fiduciary duty by Woodside, (6) misapplication ofTrust property by Pioneer, (7) conspiracy to misapply fiduciary propertyby Woodside and Pioneer, (8) common law fraud by Pioneer, (9) grossnegligence by Pioneer, and (10) breach of the conveyance agreement byPioneer. MHLP asserts claims for damages against the Trustee for (1) anaccounting; and (2) breach of fiduciary duty. The plaintiff remedies beingsought include (a) reconstruing the Trust Indenture to determine that theTrust is not terminated because there has or should have been production whichwould have generated revenues to extend the life of the Trust, (b) requiringthe Trustee to pursue certain claims, or to allow plaintiff to pursue suchclaims, (c) setting aside any farmouts by Pioneer in which there have beenconveyances to an affiliate of Pioneer in violation of the Trust’s Conveyanceand as a self-dealing transaction, (d) removing JPMorgan Chase Bank, N.A.as Trustee; (e) seeking return or forfeiture of compensation to JPMorganChase Bank, N.A. (f) recovering monetary damages against Pioneer, Woodsideand JPMorgan Chase Bank, N.A., and (g) pursuing exemplary damages againstall defendants.

On November 30, 2005, JPMorgan Chase Bank, N.A.announced its intention to resign as Trustee of the Mesa Offshore Trusteeeffective January 31, 2006. Since that announcement, MHLP and others havesought a qualified institution willing to serve as successor Trustee. However,neither MHLP nor Pioneer have identified a willing qualified successor Trusteethat is not also a lender under one of Pioneer’s credit facilities (whichstatus MHLP contends is an alleged conflict of interest).

On Friday, January 27, 2006, a hearing was heldin the 334th Judicial District Court of Harris County,Texas, regarding MHLP’s Verified Application for Emergency Appointment of aTemporary Trustee in Case No. 2006-01984, MOSH Holding, L.P. v.Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc; WoodsideEnergy (USA), Inc.; and JPMorgan Chase Bank, N.A., as Trustee of the MesaOffshore Trust. This case follows the transfer of prior claims filed by theplaintiff in Case No. GN501113. At this hearing, the court declined toapprove MHLP’s motion to appoint Timothy J. Roberson, a principal and affiliateof the plaintiff, as temporary Trustee and declined to appoint any other personas temporary or successor Trustee.

In light of this development, and the absence of anidentified successor Trustee, JPMorgan Chase Bank, N.A. withdrew itsresignation as Trustee. The Trustee continues to desire the appointment of aqualified successor Trustee.

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To date, the Trustee hasallowed MHLP to proceed on the issue of whether the farmout by Pioneer was avalid farmout, and the lawsuit remains in a phase where the parties areattempting to discover information about the claims and allegations. WhilePioneer has provided a reasoned analysis of why it believes the farmout was infact valid under the terms of the conveyance, only a court, and not theTrustee, can make a final determination. Further, while the plaintiff’s claimson the farmout issue may merit adjudication, based on facts known to theTrustee at this time, the Trustee is unable to determine, even if the plaintiffprevailed on its uncertain liability claims, whether the Trust would realizeany economic benefit. Based on information received to date, the Trustee hasnot concluded that it would be in the best interest of the unitholders to fundthe MHLP claims directly with Trust funds. However, as noted above, the Trusteehas not opposed the plaintiff’s pursuit of its claims on behalf of theunitholders at their own expense, which reasonable expenses would be subject torepayment if the claims proved successful and a benefit were conferred upon allUnitholders of the Trust. In connection with both the anticipated sale of Trustproperties pursuant to the Trust’s termination and the pending litigation, theTrustee has (1) engaged an independent reserve engineer to review theestimated reserves and (2) had an independent joint venture auditor reviewcertain historical expenditures and revenue receipts on Trust properties. TheTrustee believes expenditures for these reviews were prudent and in theinterest of the unitholder.

The Trustee will make thefull detail of the underlying data of the December 31, 2005 reserve reportavailable for use in connection with the sale of the Trust properties as partof the Trust termination. For more information regarding the estimatedremaining life of each of the Royalty Properties, the estimated future netrevenues of the Royalty Properties and information relating to farm-outs ofinterests on the Royalty Properties based on information provided by PNR to D&M,see pages 22 and 23 of this Form 10-K and Note 6 in the Notesto Financial Statements included elsewhere in this Form 10-K. Thesale 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.

**TIMING OFLIQUIDATION**

In connection with thislitigation, the Trustee has agreed that it will give MHLP at least 60 daysnotice prior to the sale of any Trust properties in connection with thetermination of the Trust. As of the date of this filing, based on theinformation currently provided by Pioneer and the preliminary state of theproceeding, the Trustee has not made any definitive conclusions as to thevalidity of the claims asserted by MHLP. However, the review of reserves by theindependent reserve engineer has not shown the existence of significantreserves not previously included in the reserve report prepared by Pioneer inquantities originally alleged in the plaintiff’s petition.

As part of the terminationprocedures, the Trustee engaged an independent joint venture auditor in October 2004to review the Trust properties as part of the termination of the Trust. Thejoint venture auditor reviewed the periods from 2003 through 2004. The Trusteebelieved this engagement of an outside expert on these matters to be a prudentstep to identify any potential benefits to the Trust, as well as any limitationson potential benefits, due to differing interpretations of accounting mattersthat commonly occur in the oil and gas production industry. The review of theindependent joint venture auditor was completed in December 2005, and itwas the joint venture auditor’s opinion that the charges and credits andrevenue to the Trust were in accordance with the applicable agreements, exceptfor certain items noted in the report. The report notes exceptions, which mayor may not turn out to be meritorious, as to amounts due to the Trust of$204,219. PNR, Stone Energy (Stone) and Newfield  Exploration Company (Newfield) have receiveda copy of the report and have 180 days to respond to these findings. As of March 15,2006, PNR, Stone and Newfield have not yet responded to the findings in thisreport.

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Due to the pendinglitigation, the Trustee cannot predict the timing of the sale of all or aportion of the Trust properties as part of the Trust Termination.

**Assetsand Liabilities in the Process of Liquidation**

As aresult of the contractual termination of the Trust effective January 1,2005, the Trust is in the process of liquidation. The below table presents theassets of the Trust at their estimated fair value:

| ** **                                                 | ** ** | **December 31,  2005** | ** ** |
|------------------------------------------------------------|------------|-----------------------------|------------|
| ASSETS                                                     |       |                        |       |   |   |
| Cash and short term  investments                           |       |                        | $          | 1,846,798 |   |   |
| Interest  receivable                                       |       |                        | 1,582      |   |   |
| Net overriding  royalty interest in oil and gas properties |       |                        | 4,831,237  |   |   |
| Total assets                                               |       |                        | 6,679,617  |   |   |
| LIABILITIES                                                |       |                        |       |   |   |
| Reserve for Trust  expenses                                |       |                        | $          | 1,848,380 |   |   |
| Total liabilities                                          |       |                        | 1,848,380  |   |   |
| Net assets in process of  liquidation                      |       |                        | $          | 4,831,237 |   |   |

 

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

·       TheTrust’s estimated share of oil and gas reserve volumes at December 31,2005, were derived from the reserve report prepared by DeGolyer and MacNaugton(D&M). The Trust’s estimated share of oil and gas reserve volumes at December 31,2005 include reserves related to the Midway Prospect.(1)

·       Forwardstrip commodity prices on December 31, 2005 for the life of the reserves.

·       Exclusionof estimated future abandonment costs.(2)

·       Discountrate of 10%.

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(1)          As a result of thelitigation described above, the Trust had been unable to obtain necessaryinformation from the working interest owner regarding such owner’s own currentestimate of the fair value of the proved reserves on the Midway Prospect. TheTrustee engaged D&M, an independent reserve engineer, to review all oil andgas reserves pertaining to the Royalty, including the Midway Prospect reservesand the Trust’s interest in these reserves as of December 31, 2005.

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

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

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For all other assets presented in the above table, theTrustee believes that historical cost approximates fair market value due to theshort-term nature of such assets. The Trustee will continue to reserve funds torecoup its previously established reserves to pay Trust expenses, which willprimarily consist of expenses incurred by the Trustee to liquidate the Trust’sassets. Any funds remaining after all expenses have been paid will bedistributed to the Unitholders.

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 to D&M, see pages 22 and 23 of this Form 10-Kand Note 6 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” on page 26 of this Form 10-K, PNR withholds fromthe Trust a reserve to cover its share of those future abandonment and removalcosts. To the extent a certain party is able to complete the abandonment for anamount less than the funds withheld by PNR, the related rights to theabandonment accrual are likely to be deemed marketable. The final distributionto untiholders will be an amount net of funds required to satisfy all Trustliabilities.

**DESCRIPTION OF ROYALTY PROPERTIES**

**ProducingAcreage and Wells as of December 31, 2005**

| ** **                   | ** ** | ** **               | ** ** | ** ** | ** ** | **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 |   |   |   | — |   |   |   | .5 |   |   |
| 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 |   |   |   | — |   |   |   | .6 |   |   |
|                              |            |                          |            |            |            |                             |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)          Dual completions arecounted as one well. For information regarding wells producing at December 31,2005, see page 34 of this Form 10-K. As of January 31,2006, only the wells on Brazos A-7 and 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)          All wells were pluggedand abandoned and the platform was abandoned on Matagorda Island 624 during2003 and the lease was relinquished.

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**DEGOLYERAND MACNAUGHTON**5001 SPRING VALLEY ROADSUITE 800 EASTDALLAS, TEXAS 75244

**APPRAISAL REPORTas ofDECEMBER 31, 2005onCERTAIN INTERESTSowned byMESA OFFSHORE TRUSTprepared forJPMORGAN CHASE BANK, N.A.**

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**TABLE of CONTENTS**

|                                 | ** ** | **Page** |
|---------------------------------|------------|----------|
| **FOREWORD**                    |       |     | 15 |   |
| Scope  of Investigation         |       |     | 15 |   |
| Authority                       |       |     | 16 |   |
| Source  of Information          |       |     | 16 |   |
| **CLASSIFICATION  of RESERVES** |       |     | 16 |   |
| **ESTIMATION  of RESERVES**     |       |     | 17 |   |
| **VALUATION  of RESERVES**      |       |     | 18 |   |
| **SUMMARY  and CONCLUSIONS**    |       |     | 19 |   |
| **APPENDIX**                    |       |     |   |   |

 

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**DEGOLYERAND MACNAUGHTON**5001 SPRING VALLEY ROADSUITE 800 EASTDALLAS, TEXAS 75244

**APPRAISAL REPORTas ofDECEMBER 31, 2005onCERTAIN INTERESTSowned byMESA OFFSHORE TRUSTprepared forJPMORGAN CHASE, N.A.**

**FOREWORD**

*Scope ofInvestigation*

This report presents an appraisal, as of December 31,2005,of the extent and value of the proved and probable crude oil, condensate, andnatural gas reserves of working and royalty interests in certain propertiesowned by the Mesa Offshore Trust (MOST) located offshore from Louisiana andTexas in the Gulf of Mexico. Also presented are estimates of the extent only ofthe possible oil, condensate, and gas reserves. The Managing General Partner isPioneer Natural Resources USA Inc. (PNR). This report was prepared at the requestof JPMorgan Chase Bank, N.A. (JPMorgan Chase), trustee for MOST.

Reserves estimated in this report are expressed asgross and net reserves. Gross reserves are defined as the total estimatedpetroleum to be produced from these properties after December 31,****2005.Net reserves are defined as that portion of the gross reserves attributable to MOST’sinterests after deducting royalties and interests owned by others.

This report presents values that were estimated forproved and proved-plus-probable reserves using initial prices provided byJPMorgan Chase and initial costs provided by PNR. Future price and costassumptions were provided by JPMorgan Chase. A detailed explanation of theprice and cost assumptions used herein is included in the Valuation of Reservessection of this report.

Values are expressed in terms of estimated futuregross revenue, future net revenue, and present worth. Future gross revenue isthat revenue which will accrue from the production and sale of the estimatednet reserves. Future net revenue is calculated by deducting estimated operatingexpenses and capital costs from the future gross revenue. Operating expensesinclude field operating expenses and the estimated expenses of directsupervision but do not include that portion of general administrative costssometimes allocated to production. Future income tax expenses were not takeninto account in the preparation of these estimates. Present worth is defined asfuture net revenue discounted at a specified arbitrary discount rate compoundedmonthly over the expected period of realization. In this report, present worthvalues using a nominal discount rate of 10 percent are reported in detail andvalues using nominal discount rates of 5, 15, 20, and 25 percent are reportedas totals in the appendix to this report.

Estimates of oil,condensate, and gas reserves and future net revenue should be regarded only asestimates that may change as further production history and additionalinformation become available. Not only are such reserves and revenue estimatesbased on that information which is currently available, but 

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suchestimates are also subject to the uncertainties inherent in the application ofjudgmental factors in interpreting such information.

*Authority*

This report was authorizedby Mr. Mike Ulrich, Vice President, JPMorgan Chase.

*Source ofInformation*

Information used in thepreparation of this report was obtained from PNR’s****fileson behalf of JPMorgan Chase, from records on file with the appropriateregulatory agencies, and from public sources. In the preparation of this reportwe have relied, without independent verification, upon such informationfurnished by PNR and JPMorgan Chase with respect to property interests,production from such properties, current costs of operation and development,current prices for production, the future plans for development of theproperties, agreements relating to current and future operations and sale ofproduction, and various other information and data that were accepted asrepresented. A field examination of the properties was not considered necessaryfor the purposes of this report.

**CLASSIFICATION of RESERVES**

Petroleum reserves are classified by degree of proofas proved, probable, or possible. Proved reserves are judged to be economicallyproducible in future years from known reservoirs under existing economic andoperating conditions and assuming continuation of current regulatory practicesusing conventional production methods and equipment. In the analyses ofproduction-decline curves, reserves were estimated only to the limit ofeconomic rates of production under existing economic and operating conditionsusing prices and costs as of the date the estimate is made, includingconsideration of changes in existing prices provided only by contractualarrangements but not including escalations based upon future conditions. Thepetroleum reserves are classified as 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, ifany, 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 andnonproducing reserves. Estimates of producing reserves assume recovery byexisting wells producing from present completion intervals with normaloperating methods and expenses. Developed nonproducing reserves are inreservoirs behind the casing or at minor depths below the producing zone andare considered proved by production from other wells in the field, bysuccessful drill-stem tests, or by core analyses from the particular zones.Nonproducing reserves require only moderate expense to be brought intoproduction.

*Undeveloped—**Reserves*that arerecoverable from additional wells yet to be drilled.

Undeveloped reserves are those considered proved forproduction by reasonable geological interpretation of adequate subsurfacecontrol in reservoirs that are producing or proved by other wells but are notrecoverable from existing wells. This classification of reserves requiresdrilling of 

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additional wells, majordeepening of existing wells, or installation of enhanced recovery or other facilities.

*Probable—**Reserves* susceptibleof being proved that are based on reasonable evidence of produciblehydrocarbons within the limits of a structure or reservoir above known orinferred fluid contacts but are defined to a lesser degree of certainty becauseof more limited well control and/or the lack of definitive production tests.Probable reserves may include extensions of proved reservoirs or otherreservoirs that have not been tested at commercial rates of flow or reservesrecoverable by enhanced recovery methods that have not yet been tested in thesame reservoir or where there is reasonable uncertainty that the program willbe implemented.

*Possible—**Reserves* that mayexist but are less well defined by well control than probable reserves.Possible reserves include those based largely on log interpretation and otherevidence of hydrocarbon saturation in zones behind the pipe in existing wells,possible extensions to proved and probable reserves areas where indicated bygeophysical or geological studies, and those to be recovered by enhancedrecovery methods where the data are insufficient to classify the reserves asproved or probable.

The extent to whichprobable and possible reserves ultimately may be reclassified as provedreserves is dependent upon future drilling, testing, and well performance. Thedegree of risk to be applied in evaluating probable and possible reserves isinfluenced by economic and technological factors as well as the time element.Probable and possible reserves in this report have not been adjusted inconsideration of these additional risks and therefore are not comparable withproved reserves.

**ESTIMATION of RESERVES**

Estimates of reserves were prepared by the use ofstandard geological and engineering methods generally accepted by the petroleumindustry. The method or combination of methods used in the analysis of eachreservoir was tempered by experience with similar reservoirs, stage ofdevelopment, quality and completeness of basic data, and production history.

The volumetric method was used to estimate theoriginal oil in place (OOIP) and original gas in place (OGIP). Structure mapswere prepared to delineate each reservoir, and isopach maps were constructed toestimate reservoir volume. Electrical logs, radioactivity logs, core analyses,and other available data were used to prepare these maps as well as to estimaterepresentative values for porosity and water saturation.

Estimates of ultimate recovery were obtained afterapplying recovery factors to OOIP or OGIP. These recovery factors were based onconsideration of the type of energy inherent in the reservoirs, analyses of thepetroleum, and the structural positions of the properties.

The rates used for future oil, condensate, and gasproduction are estimated to be within the capacity of a well or reservoir toproduce. Data available from wells drilled on the appraised properties through December 31,2005, were used to prepare the estimates shown herein. Gross production throughDecember 31,****2005, was deducted from the grossultimate recovery to arrive at estimates of gross reserves. Production from theproperties was halted in the third quarter of 2005 as a result of hurricanes.Production is expected to resume in the first quarter of 2006.

Gas volumes estimated herein are expressed as salesgas at a temperature base of 60 degrees Fahrenheit (°F) and a pressure base of14.73 pounds per square inch absolute (psia). Sales gas is defined as the totalgas to be produced from the reservoirs, measured at the point of delivery, afterreduction for fuel usage, flare, and shrinkage resulting from field separationand processing. Condensate reserves estimated herein are those to be obtainedby normal separator recovery.

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Estimates of the gross andnet proved, probable, and possible reserves, as of December 31,****2005,of the properties appraised are presented as follows. Oil and condensatereserves are expressed in barrels (bbl) and gas reserves are expressed inthousands of cubic feet (Mcf).

| ** **     | ** ** | **Oil and  Condensate  (bbl)** | ** ** | **Sales Gas  (Mcf)** | ** ** |
|----------------|------------|-------------------------------------|------------|---------------------------|------------|
| Gross Reserves |       |                                |       |                      |       |   |   |
| Proved         |       |                                | 141,777    |                      |       | 7,083,449 |   |
| Probable(1)    |       |                                | 40,919     |                      |       | 5,351,000 |   |
| Possible(1)    |       |                                | 25,590     |                      |       | 8,530,000 |   |
| Net Reserves   |       |                                |       |                      |       |   |   |
| Proved         |       |                                | 10,766     |                      |       | 460,055 |   |
| Probable(1)    |       |                                | 2,818      |                      |       | 293,244 |   |
| Possible(1)    |       |                                | 1,281      |                      |       | 426,500 |   |

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(1)          Probableand possible reserves have not been risk adjusted.

**VALUATION of RESERVES**

This report has beenprepared using initial prices provided by JPMorgan Chase and initial costsprovided by PNR on behalf of JPMorgan Chase. Future prices were estimated usingguidelines established by the United States Securities and Exchange Commission(SEC) and the Financial Accounting Standards Board (FASB). In this report,values for proved and proved-plus-probable reserves were based on projectionsof estimated future production and revenue prepared for these properties withno risk adjustment applied to the probable reserves. Probable reserves involvesubstantially higher risks than proved reserves. Revenue values forproved-plus-probable reserves have not been adjusted to account for such risks;this adjustment would be necessary in order to make values forproved-plus-probable reserves comparable with values for proved reserves.

*Oil and CondensatePrices*

Initial oil and condensate prices furnished byJPMorgan Chase, after adjustments for differentials, varied from $57.61 to $58.01 per barrel and were held constant for the producing livesof the properties.

*Natural Gas Prices*

The natural gas prices also furnished by JPMorganChase, after adjustments for differentials, varied from $7.31 to $9.86 perthousand cubic feet of gas and were held constant for the producing lives ofthe properties.

*Operating Expensesand Capital Costs*

Estimates of the operating expenses were provided byPNR and were held constant for the lives of the properties. Future capitalexpenditures were provided by PNR using current values and were held constantto the date of the expenditure.

*AbandonmentCosts and Salvage Value*

Costs for abandonment of the working-interest wellwere offset by the salvage value estimated by PNR.

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The estimated future revenue to be derived from theproduction and sale of MOST’s net proved and proved-plus-probable reserves, asof December 31, 2005, under the economic assumptions furnished by JPMorganChase is summarized as follows:

| ** **                      | ** ** | **Proved  ($)** | ** ** | **Proved plus  Probable(1)  ($)** | ** ** |
|---------------------------------|------------|-----------------|------------|----------------------------------------|------------|
| Future Gross  Revenue           |       | 4,625,213       |       |                                   | 7,114,303  |   |   |
| Operating  Expenses             |       | 64,641          |       |                                   | 64,641     |   |   |
| Capital Costs                   |       | 0               |       |                                   | 0          |   |   |
| Future Net  Revenue(2)          |       | 4,560,572       |       |                                   | 7,049,662  |   |   |
| Present Worth at 10  Percent(2) |       | 3,821,991       |       |                                   | 5,745,130  |   |   |

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(1)          There has been noadjustment to the value of the probable reserves to account for risk.

(2)          Future income taxexpenses were not taken into account in the preparation of these estimates.

The appendix bound with this report presentstabulations and projections of revenue from the proved and non-risk-adjustedproved-plus-probable reserves for the interests appraised. Also included aresummaries of the probable and possible reserves.

In our opinion, the information relating to estimatedproved reserves, estimated future net revenue from proved reserves, and presentworth of estimated future net revenue from proved reserves of oil, condensate,and gas contained in this report has been prepared in accordance withParagraphs 10-13, 15 and 30(a)-(b) of Statement of Financial AccountingStandards No. 69 (November 1982) of the FASB and Rules 4-10(a) (1)-(13)of Regulation S-X and Rule 302(b) of Regulation S-K of the SEC; provided,however, that (i) certain estimated data have not been provided with respect tochanges in reserves information and (ii) future income tax expenses have notbeen taken into account in estimated the future net revenue and present worthvalues set forth herein. Other rules and regulations of the SEC containspecific provisions that prohibit the reporting of probable and possiblereserves; therefore, the reporting and filing with the SEC of the probable orpossible reserves and the values based on proved-plus-probable reservescontained herein would not be in conformity with such rules andregulations and should not, under any circumstances, be used or relied upon tomeet the requirements thereof.

To the extent theabove-enumerated rules, regulations, and statements require determinations ofan accounting or legal nature or information beyond the scope of our report, weare necessarily unable to express an opinion as to whether the above-describedinformation is in accordance therewith or sufficient therefore.

**SUMMARY and CONCLUSIONS**

Evaluatedherein are working and royalty interests in certain properties owned by MOSTlocated offshore from Louisiana and Texas in the Gulf of Mexico. Estimates of MOST**’s** net proved, probable, and possible reserves, as of December 31**,**2005,of the properties appraised are presented as follows. Oil and condensatereserves are expressed in barrels (bbl) and gas reserves are expressed inthousands of cubic feet (Mcf).

| ** **                   | ** ** | **Proved** | ** ** | **Probable(1)** | ** ** | **Possible(1)** | ** ** |
|------------------------------|------------|------------|------------|-----------------|------------|-----------------|------------|
| Net Oil and  Condensate, bbl |       | 10,766     |       |            | 2,818      |            |       |   | 1,281 |   |   |
| Net Sales Gas, Mcf           |       | 460,055    |       |            | 293,244    |            |       |   | 426,500 |   |   |

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(1)          Probable and possiblereserves have not been risk adjusted.

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Revenue and costsattributable to MOST**’s** interests inthe proved and proved-plus-probable reserves, as of December 31, 2005, ofthe properties evaluated under the aforementioned assumptions concerning futureprices and costs are estimated as follows:

| ** **                     | ** ** | **Proved  ($)** | ** ** | **Proved plus  Probable(1)  ($)** | ** ** |
|--------------------------------|------------|-----------------|------------|----------------------------------------|------------|
| Future Gross  Revenue          |       | 4,625,213       |       |                                   | 7,114,303  |   |   |
| Operating  Expenses            |       | 64,641          |       |                                   | 64,641     |   |   |
| Capital Costs                  |       | 0               |       |                                   | 0          |   |   |
| Future Net  Revenue(2)         |       | 4,560,572       |       |                                   | 7,049,662  |   |   |
| Present Worth at 10 Percent(2) |       | 3,821,991       |       |                                   | 5,745,130  |   |   |

----

(1)          There has been noadjustment to the value of the probable reserves to account for risk.

(2)          Future income tax expenseswere not taken into account in the preparation of these estimates.

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Gasvolumes estimated herein are expressed at a temperature base of 60 °F and apressure base of 14.73 psia.
|                                | Submitted,               |
|--------------------------------|--------------------------|
|                           |                          |
|                           | DeGOLYER and MacNAUGHTON |
| SIGNED:  February 1, 2006 |                     |
|                                |                          |
|                           | Paul J. Szatkowski, P.E. |
|                           | Senor Vice President     |
|                           | DeGolyer and MacNaughton |

 

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**Reserves**

A study of the proved oil and gas reservesattributable to the Partnership as of December 31, 2005, has been made byD&M. The following letter (the “Reserve Report”) summarizes such reservestudy. 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 further informationregarding the Net Overriding Royalty Interest, the Basis of Accounting for theTrust and Supplemental Reserve Information, see Notes 2, 3 and 6, respectively,in the Notes to Financial Statements contained in Item 8 of this Form 10-K.

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.Reserve assessment is a subjective process of estimating the recovery fromunderground accumulations of gas and oil that cannot be measured in an exactway and estimates of other persons might differ materially from those ofD&M. Accordingly, reserve estimates are often different from the quantitiesof hydrocarbons 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 to thePartnership 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, 2005. These prices (having weighted average yearend prices of $57.61 to $58.01 per barrel and $7.31 to $9.86 per Mcf as of December 31,2005) 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 2005 was $7.01 per Mcf, representing acombination of contract prices and spot market prices, while the average priceof crude oil, condensate and natural gas liquids was $48.97 per barrel.

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Thefollowing is a summary of the estimated remaining life for each of the RoyaltyProperties provided to the Trustee by D&M as of December 31, 2005.There are numerous uncertainties present in estimating the remaining productivelives for the Royalty Properties. The following summary represents an estimateonly and should not be construed as being exact. The estimated remainingproductive life of each property varies depending on the recoverable reservesand annual production assumed by D&M. In addition, future economic andoperating conditions may cause significant changes in these estimates.

| **Property**  | ** ** | ** ** | ** ** | **Productive Life(1)(2)** | ** ** |
|---------------|------------|------------|------------|--------------------------------|------------|
| West Delta 61 |       |       | 7 years    |                           |       |
| Brazos A-7    |       |       | 2 years    |                           |       |
| Brazos A-39   |       |       | 2 years    |                           |       |

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(1)          The Trust will terminatein the event the total amount of cash received per year by the Trust fallsbelow certain levels. Accordingly, it would be possible for the Trust toterminate even though some of the Royalty Properties continued to haveremaining productive lives. See “Legal Proceedings and Status of the Trust” onpage 8 of this Form 10-K and see “Timing of Liquidation” on page 10of this Form 10-K.

(2)          Estimates of remaininglives 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.

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.

**CONTRACTS**

**General**

PNR has advised the Trustthat during 2005 its offshore gas production was marketed under short-termcontracts at spot market prices primarily to TOTAL S.A. PNR has further advisedthe Trust that it expects to continue to market its production under short-termcontracts for the foreseeable future. Spot market prices for natural gas in2005 were generally higher than spot market prices in 2004.

**Market for Natural Gas**

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 $2.95per Mcf in 2002, increased to $5.09 per Mcf in 2003, to $5.49 per Mcf in 2004and increased to $5.65 in 2005 according to the Natural Gas Monthly publishedby the Energy Information Administration 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 

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year dueprimarily to peak demand in these periods. Because of the time lag between thedate on which PNR receives payment for production from the Royalty Propertiesand the date on which distributions are made to unitholders, the seasonalitythat generally affects production volumes and prices is generally reflected indistributions to 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.

**Marketing of Liquids**

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

**REGULATION AND 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.

**OperatingHazards and 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 basedon environmental 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 

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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 Other Regulation**

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.

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 ispossible that future changes in the regulations and statutes may occur whichmay increase 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”) 

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adopted regulations forestablishing the amount of OSFR required for particular facilities. The amountof OSFR increases as the volume of a facility’s worst-case oil spill increases.Accordingly, for facilities with worst-case spills of less than 35,000 barrels,only $35 million in OSFR is required; for worst-case spills of over 35,000barrels, $70 million is required; for worst-case spills of over 70,000barrels, $105 million is required; and for worst-case spills of over105,000 barrels, $150 million is required. In addition, all OSFR below$150 million remains subject to upward regulatory adjustment if warrantedby the particular operational, environmental, human health or other risksinvolved with a facility. Under this regulation, PNR is required to maintain$35 million in OSFR for its offshore facilities. PNR is maintaining itsOSFR in this amount by insurance. Although the working interest owners haveadvised the Trust that current environmental regulation has had no materialadverse effect on the working interest owners’ present method of operations,the impact of the recently adopted regulatory changes, and of futureenvironmental regulatory developments such as stricter environmental regulationand enforcement 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.

**Platform Abandonment 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 3 in theNotes to Financial Statements for amounts withheld as of December 31, 2005and amounts to be withheld in the future.

**Item 1A.     RiskFactors.**

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.

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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.

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 or too low.**

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.

The Trustee also relies entirely on reserve estimates andrelated information prepared by PNR and the independent  reserve engineer engaged by the Trust. Whilethe Trustee has no reason to believe the reserve estimates and relatedestimates of value included in this report are not accurate, to the extentadditional information exists that could affect their reserve estimates, theestimated reserves in these reports and related estimates of value could alsobe too low.

**Estimates andaccruals of costs by PNR may be greater or lesser than future estimated oractual costs.**

As discussed in Item 7 and Note 3 to theNotes to Financial Statements, at December 31, 2005 PNR has withheldapproximately $348,066 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 

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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.Only unitholders 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 ortransportation accidents at any of the Royalty Properties will reduce Trustdistributions by the amount of uninsured costs. These occurrences includeblowouts, cratering, explosions and other environmental damage. Offshoreactivities are also subject to a variety of operating risks such as hurricanesand other weather disturbances. These accidents and other natural disasters mayresult in personal injuries, property damage, damage to productive formationsor equipment and environmental damages. Any uninsured costs would be deductedas a production cost in calculating net proceeds payable to the Trust.

**The operators of theworking interests are subject 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. These regulations and changes inregulations could have a material adverse effect on Royalty income payable tothe Trust.

**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 Trustee reliesupon the working interest owners and managing general partner for informationregarding the Royalty Properties.**

The Trustee relies on the working interest owners andmanaging general partner for information regarding the Royalty Properties. Theworking interest owners alone control (i) historical operating data,including production volumes, marketing of products, operating and capitalexpenditures, environmental and other liabilities, 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 related projections regarding production, operatingexpenses and capital expenses used in connection with the preparation of thereserve report, (iv) forward-looking information relating to productionand drilling plans and (v) information regarding the Royalty Propertiesresponsive to litigation claims. While the Trustee requests materialinformation for use in periodic reports as part of its disclosure controls andprocedures, the Trustee does not control this information and relies entirelyon the working interest owners to provide accurate and timely information whenrequested for use in the Trust’s periodic reports. The Trustee also relies onthe managing general partner of the Partnership to collect certain informationfrom the working interest owners and does not have any direct contact with theworking interest owners other than the managing general partner. Under theterms of the Trust Indenture, the Trustee is entitled to rely, and in factrelies, on certain experts in good faith. While the Trustee has no reason tobelieve its reliance on experts is unreasonable, this reliance on experts andlimited access to information may be viewed as a weakness as compared to themanagement and oversight of entity forms other than trusts.

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**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—Legal Proceedings and Status of the Trust and Timing of Liquidation”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—Legal Proceedings and Status of theTrust and Timing of Liquidation.”

**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”.

**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 

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belimited to bringing a lawsuit against the Trustee to compel the Trustee to takespecified actions. Unitholders probably would not be able to sue the workinginterest owner directly.

**Item 1B.**               UnresolvedStaff Comments.

There were no unresolvedSecurities and Exchange Commission comments as of December 31, 2005.

**Item 2.**                        Properties.

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

**Item 3.**                        LegalProceedings.

On April 11, 2005, MOSH Holding, L.P. (MHLP)filed an Original Petition in the District Court of Travis County, Texas, 250thJudicial District, against Pioneer Natural Resources Company; Pioneer NaturalResources USA, Inc.; Woodside Energy (USA), Inc.(Woodside); andJPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (Case No. GN501113).On November 28, 2005, Plaintiff amended its petition. In the amendedpetition, MHLP asserts claims against Pioneer and Woodside for matters including(1) a wrongful farmout of Brazos A-39 by Pioneer, (2) awrongful delay by Pioneer in producing Brazos A-39, (3) fraudulentaccounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aidingand abetting breach of fiduciary duty by Woodside, (6) misapplication ofTrust property by Pioneer, (7) conspiracy to misapply fiduciary propertyby Woodside and Pioneer, (8) common law fraud by Pioneer, (9) grossnegligence by Pioneer, and (10) breach of the conveyance agreement byPioneer. MHLP asserts claims for damages against the Trustee for (a) anaccounting; and (2) breach of fiduciary duty. The plaintiff remedies beingsought include (a) reconstruing the Trust Indenture to determine that theTrust is not terminated because there has or should have been production whichwould have generated revenues to extend the life of the Trust, (b) requiringthe Trustee to pursue certain claims, or to allow plaintiff to pursue suchclaims, (c) setting aside any farmouts by Pioneer in which there have beenconveyances to an affiliate of Pioneer in violation of the Trust’s Conveyanceand as a self-dealing transaction, (d) removingJPMorgan Chase Bank, N.A. as Trustee; (e) seeking return or forfeiture ofcompensation to JPMorgan Chase Bank, N.A. (f) recovering monetary damagesagainst Pioneer, Woodside and JPMorgan Chase Bank, N.A., and (g) pursuingexemplary damages against all defendants.

On November 30, 2005, JPMorgan Chase Bank, N.A.announced its intention to resign as Trustee of the Mesa Offshore Trusteeeffective January 31, 2006. Since that announcement, MHLP and others havesought a qualified institution willing to serve as successor Trustee. However,neither MHLP nor Pioneer have identified a willing qualified successor Trusteethat is not also a lender under one of Pioneer’s credit facilities (whichstatus MHLP contends is an alleged conflict of interest).

On Friday, January 27, 2006, a hearing was heldin the 334th Judicial District Court of Harris County,Texas, regarding MHLP’s Verified Application for Emergency Appointment of aTemporary Trustee in Case No. 2006-01984, MOSH Holding, L.P. v.Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc; WoodsideEnergy (USA), Inc.; and JPMorgan Chase Bank, N.A., as Trustee of the MesaOffshore Trust. This case follows the transfer of prior claims filed by theplaintiff in Case No. GN501113. At this hearing, the court declined toapprove MHLP’s motion to appoint Timothy J. Roberson, a principal and affiliateof the plaintiff, as temporary Trustee and declined to appoint any other personas temporary or successor Trustee.

In light of this development, and the absence of anidentified successor Trustee, JPMorgan Chase Bank, N.A. withdrew itsresignation as Trustee. The Trustee continues to desire the appointment of aqualified successor Trustee.

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To date, the Trustee has allowed MHLP to proceed onthe issue of whether the farmout by Pioneer was a valid farmout, and thelawsuit remains in a phase where the parties are attempting to discoverinformation about the claims and allegations. While Pioneer has provided areasoned analysis of why it believes the farmout was in fact valid under theterms of the conveyance, only a court, and not the Trustee, can make a finaldetermination. Further, while the plaintiff’s claims on the farmout issue maymerit adjudication, based on facts known to the Trustee at this time, the Trusteeis unable to determine, even if the plaintiff prevailed on its uncertainliability claims, whether the Trust would realize any economic benefit. Basedon information received to date, the Trustee has not concluded that it would bein the best interest of the unitholders to fund the MHLP claims directly withTrust funds. However, as noted above, the Trustee has not opposed the plaintiff’spursuit of its claims on behalf of the unitholders at their own expense, whichreasonable expenses would be subject to repayment if the claims provedsuccessful and a benefit were conferred upon all Unitholders of the Trust. Inconnection with both the anticipated sale of Trust properties pursuant to theTrust’s termination and the pending litigation, the Trustee has (1) engagedan independent reserve engineer to review the estimated reserves and (2) hadan independent joint venture auditor review certain historical expenditures andrevenue receipts on Trust properties. The Trustee believes expenditures forthese reviews were prudent and in the interest of the unitholder.

The Trustee will make thefull detail of the underlying data of the December 31, 2005 reserve reportavailable for use in connection with the sale of the Trust properties as partof the Trust termination. For more information regarding the estimatedremaining life of each of the Royalty Properties, the estimated future netrevenues of the Royalty Properties and information relating to farm-outs ofinterests on the Royalty Properties based on information provided by PNR to D&M,see pages 22 and 23 of this Form 10-K and Note 6 in theNotes 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” on page 26 of this Form 10-K, PNR withholdsfrom the Trust a reserve to cover its share of those future abandonment andremoval costs. To the extent a certain party is able to complete theabandonment for an amount less than the funds withheld by PNR, the relatedrights to the abandonment accrual are likely to be deemed marketable. The finaldistribution to unitholders will be an amount net of funds required to satisfyall Trust liabilities.

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

There were no matters submitted to a vote ofunitholders during the fourth quarter of 2005.

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**PART II**

**Item 5.   Market for the Registrant’s CommonEquity 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 2005. In 2005, theTrust had gross Royalty income of $2,356,256; however during 2005, PNR recoupeddeficit balances of  $71,342; net Royaltyincome to the Trust was $2,284,914 in 2005. No Royalty income will bedistributed to the unitholders until the Trustee recoups Trust expenses beingpaid from the reserve that the Trustee has established for anticipated futureexpenses. The high and low sales prices and distributions per unit for eachquarter in the two years ended December 31, 2005 were as follows:

| ** **     | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------|------------|----------|------------|----------|------------|
| ** **     | ** ** | **High** | ** ** | **Low**  | ** ** | **Distribution  Paid** | ** ** | **High** | ** ** | **Low** | ** ** | **Distribution  Paid** | ** ** |
| First Quarter  |       | $        | 0.04       |     | $          | 0.02 |   |   | $ | — |   |   | $ | 0.05 |   | $ | 0.03 |   |   | $ | — |   |   |
| Second Quarter |       | $        | 0.04       |     | $          | 0.02 |   |   | $ | — |   |   | $ | 0.05 |   | $ | 0.03 |   |   | $ | — |   |   |
| Third Quarter  |       | $        | 0.07       |     | $          | 0.03 |   |   | $ | — |   |   | $ | 0.04 |   | $ | 0.02 |   |   | $ | — |   |   |
| Fourth Quarter |       | $        | 0.12       |     | $          | 0.04 |   |   | $ | — |   |   | $ | 0.04 |   | $ | 0.02 |   |   | $ | — |   |   |

 

At March 14, 2006,the 71,980,216 units outstanding were held by 11,800 unitholders of record.

**Item6.   Selected Financial Data.**

| ** **                       | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
|----------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| Royalty income                   |       | $        | 2,284,914  |     | $          | —   |       | $        | —     |     | $          | — |   | $ | 1,772,595 |   |
| Distributable  income            |       | $        | —     |     | $          | —   |       | $        | —     |     | $          | — |   | $ | 1,401,106 |   |
| Distributable  income per  unit  |       | $        | —     |     | $          | —   |       | $        | —     |     | $          | — |   | $ | 0.0195 |   |
| Accumulated  deficit at year end |       | $        | —     |     | $          | (59,035  | )          | $        | (696,712   | )        | $          | (825,616 | ) | $ | (81,329 | ) |
| Total assets at year  end.       |       | $        | 1,851,428  |     | $          | 387,986  |       | $        | 951,557    |     | $          | 1,497,883 |   | $ | 2,153,070 |   |

 

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**Item7.**   Management’s Discussion and Analysisof 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.

**CriticalAccounting Policies**

The financial statementsof the Trust are prepared on the following basis:

(a)   Royalty income recorded for a month is the Trust’s interest in theamount computed and paid by the working interest owner to the Partnership forsuch month rather than either the value of a portion of the oil and gas sold bythe working interest owner for such month or the amount subsequently determinedto be 90% of the net proceeds for such month;

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

(c)   Trust general and administrative expenses are recorded in themonth they accrue and are recoupable from Royalty income.

This basis for reportingdistributable income is considered to be the most meaningful becausedistributions to the unitholders for a month are based on net cash receipts forsuch month. However, it will differ from the basis used for financialstatements prepared in accordance with accounting principles generally acceptedin the United States of America because, under such accounting principles,royalty income for a month would be based on net proceeds from sales for suchmonth without regard to when calculated or received and interest income for amonth would be calculated only through the end of such month.

**Status of the Trust**

HurricaneKatrina struck the Gulf of Mexico in August 2005. PNR notified the Trustthat it had received preliminary assessments regarding damages from HurricaneKatrina to the West Delta production facilities in which the Trust has aninterest. The operator of the West Delta properties has informed PNR that theWest Delta properties have been shut in since August 27, 2005 due todamage to the platform, the pipeline and the sales terminal. The operator hasnotified PNR that the pipeline has not been repaired and currently there is noestimate as to when the repairs will be completed. The operator does not havean estimate on when production at West Delta will resume.

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. **As a result of continued declines inproduction on Royalty Properties nearing the end of their estimated productivelives, Royalty income received by the Trust in 2002, 2003 and 2004 fell belowthe Termination Threshold prescribed by the Trust Indenture**. TheTrustee has taken steps to begin the process of liquidating the Trust. See “Timingof Liquidation” below in this Note. 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 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 

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it maynot be open to anyone who does not satisfy these requirements. The Trustee iscurrently reviewing a potential online bidding process for participants inorder to provide current public information on bidding to the marketplace. TheTrustee will also determine a duration of bidding that it deems in the bestinterest of the Unitholders.

Below is additionalinformation regarding the Trust properties provided by D&M:

*Properties producing as of December 31, 2005*

| **Property**            | ** ** | ** ** | ** ** | **Number of  Producing  wells(1)** | ** ** | **Estimated  Productive  Life(1)** | ** ** | **Estimated  Future  Royalty  Income(2)** | ** ** |
|-------------------------|------------|------------|------------|-----------------------------------------|------------|------------------------------------|------------|-------------------------------------------|------------|
| West Delta  No. 61 |       |       | 4          |                                    |       |                               | 7 years    |                                      |       | $ | 2,458,852 |   |
| Brazos A-7              |       |       | 1          |                                    |       |                               | 2 years    |                                      |       | $ | 1,363,139 |   |

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(1)          Information obtainedfrom December 31, 2005 reserve report prepared by D&M.

(2)          Representsestimated future royalty income from the December 31, 2005, reservereport. Future royalty income was calculated using oil and gas spot prices ineffect at December 31, 2005 of $57.61 to $58.01 per barrel and $7.31 to$9.86 per thousand cubic feet.

*Properties abandoned or scheduled for abandonment asof December 31, 2005*

| **Property**           | ** ** | ** **                                                                      | ** ** | **Status** |
|------------------------|------------|---------------------------------------------------------------------------------|------------|------------|
| Brazos A-7             |       | Abandoned in 2005  (excluding producing well and platform)                      |
| Brazos A-39            |       | Plug and abandonment  procedures completed 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.

**Financial and Operational Review**

As discussed in Item 1 of this Form 10-K,PNR has advised the Trust that during 2005, its offshore gas production wasmarketed under short-term contracts at spot market prices primarily to TOTALS.A. and that it expects to continue to market its production under short-termcontracts for the foreseeable future. Spot market prices for natural gas wereon the average higher in 2005 than spot market prices in 2004.

The amount of cash distributed by the Trust isdependent on, among other things, the sales prices and quantities of gas, crudeoil, condensate and natural gas liquids produced from the Royalty Propertiesand the quantities sold. Substantial uncertainties exist with regard to futuregas and oil prices, which are subject to fluctuations due to the regionalsupply and demand for natural gas and oil, production levels and otheractivities of the Organization of the Petroleum Exporting Countries (“OPEC”)and other oil and gas producers, weather, storage levels, industrial growth,conservation measures, competition and other variables.

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Belowis a summary of Royalty income received on the Trust properties for each of thethree years ending December 31, 2005:

| ** **                           | ** ** | **2005**  | ** ** | **2004** | ** ** | **2003** | ** ** |
|--------------------------------------|------------|-----------|------------|----------|------------|----------|------------|
| Gross proceeds @  90%                |       | $         | 2,085,418  |     | $          | 810,336  |       | $ | 745,192 |   |
| Operating expenditures  @ 90%        |       | (104,265  | )          | (172,594 | )          | (605,927 | )          |
| Capital  expenditures @ 90%(1)       |       | 375,338   |       | —   |       | (10,348  | )          |
| Net proceeds  (deficit)              |       | 2,356,491 |       | 637,742  |       | 128,917  |       |
| Increase  (decrease) in deficit      |       | (71,349   | )          | (637,742 | )          | (128,917 | )          |
| Net proceeds  after deficit recovery |       | 2,285,142 |       | —   |       | —   |       |
| Royalty income (99.99%)              |       | $         | 2,284,914  |     | $          | —   |       | $ | — |   |

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(1)   PNRbelieves that the future abandonments have been fully funded, no such amountswere withheld in 2004 or 2005. In 2005, the Trust received gross proceeds of$375,338 from PNR related to the sale of the South Marsh Island 155 platformthat was abandoned by PNR and for casings related to the PNR platform at BrazosA-39.

Belowis a summary of distributable income for the years ended December 31,2005, 2004 and 2003:

| ** **                              | ** ** | **Years Ended December 31,** | ** ** |
|-----------------------------------------|------------|---------------------------------------------|------------|
| ** **                              | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| Royalty income                          |       | $                                           | 2,284,914  |   | $ | — |   | $ | — |   |
| Interest income                         |       | 8,512                                       |       | 4,493 |   | 9,169 |   |
| General and  administrative expenses    |       | (2,293,426                                  | )          | (4,493 | ) | (9,169 | ) |
| Distributable  income                   |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Distributable  income per unit          |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Accumulated deficit (as  of period end) |       | $                                           | —     |   | $ | (59,035 | ) | $ | (696,712 | ) |

 

Belowis a summary of general and administrative expenses and the adjustments made tothe reserve for trust expenses:

| ** **                                                 | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                 | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| General and  administrative costs incurred during the year |       | $                                           | 824,691    |   | $ | 567,461 |   | $ | 612,572 |   |
| Adjustments to  reserve for trust expenses                 |       | 1,456,428                                   |       | (562,968 | ) | (603,403 | ) |
| General and  administrative costs as reported              |       | $                                           | 2,281,119  |   | $ | 4,493 |   | $ | 9,169 |   |

 

General and administrativeexpenses of the Trust for 2005 increased 45% to $824,691 for 2005 as comparedto $567,461 for 2004.  The increase ingeneral and administrative expenses in 2005 is primarily due to an increase inlegal fees as a result of pending litigation and the anticipated sale of Trustproperties pursuant to the Trust’s termination. In addition, the Trust incurred additional expenditures in 2005 for theindependent reserve studies performed as of March 31, 2005 andDecember 31, 2005 and for the independent joint venture auditor to performa review of certain historical expenditures and revenue receipts on Trustproperties.

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Belowis an operational review of the remaining producing Trust properties:

***Brazos A-7and A-39***

| ** **                    | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Gross proceeds @  90%         |       | $        | 156,378    |     | $          | 160,014  |       | $ | 193,039 |   |
| Operating  expenditures @ 90% |       | (83,470  | )          | (171,043 | )          | (429,232 | )          |
| Capital  expenditures @ 90%   |       | 6,750    |       | —   |       | 2,481    | )          |
| Net proceeds (deficit)        |       | $        | 79,658     |     | $          | (11,029  | )          | $ | (233,712 | ) |

 

| Production  Volumes and Average Prices:                    |   |   |   |   |   |   |   |
|------------------------------------------------------------|--------|--------|--------|--------|--------|--------|--------|
| Crude oil, condensate and natural gas  liquids (Bbls) |   | 52     |   | 36     |   | 348    |   |
| Average sales price per Bbl                                |   | $      | 52.59  |   | $      | 35.78  |   | $ | 27.42 |   |
| Natural gas (Mcf)                                          |   | 23,928 |   | 29,145 |   | 35,644 |   |
| Average sales price per Mcf                                |   | $      | 6.42   |   | $      | 5.45   |   | $ | 5.15 |   |
| Producing wells                                            |   | 1      |   | 1      |   | 1      |   |

 

The Brazos A-7 and A-39 blocks continuedto experience a decrease in natural gas production due to natural productiondecline. As of December 31, 2005, these two blocks had one well producing,the Brazos A-7 No. B-1 well which is operated by NewfieldExploration Company. The Brazos A-39 No. A-3 well ceasedproduction during the fourth quarter of 2003. PNR entered into farmoutagreements for the Trust’s interest in both of these blocks so that twoexploration prospects could be drilled and in which the Trust will retain anoverriding royalty interest. The first prospect on Brazos A-7 was drilledduring 2003 and was determined to be a dry hole. As such, the well was pluggedand abandoned. In 2005, PNR has performed abandonment procedures at the PNRoperated Brazos A-7 and the A-39 blocks, with minor siteworkclearance remaining. In 2005, the Trust received a $6,750 credit for casingsrelated to the PNR platform at Brazos A-39.

The second exploration prospect was drilled on BrazosA-39, which PNR has announced as a discovery. A production test wascompleted during the first quarter of 2005. PNR, the operator on this property,has informed the Trustee that the lower horizon of the prospect was determinedto be non-commercial, while the middle horizon produced at 10 million cubicfeet of gas per day during a seventeen hour flow test. There is no assurancethat these flow rates will continue, as offshore oil and gas properties oftenexperience stronger initial flow rates and more rapid declines than onshoreproperties. PNR expects to tie-back this prospect into an existing platform,operated by a third party, with first production expected to commence in thefirst half of 2006. Under the terms of a Farmout Agreement between PNR andWoodside Energy (USA) Inc., PNR farmed out to Woodside the undivided one-halfinterest previously burdened by the Trust’s net profits interest, but expresslyproviding that the farmed out interest would not be subject to the Trust’s netprofits interest. PNR reserved a 10% overriding royalty interest,proportionately reduced to the interest conveyed, which interest, upon Woodside’srecoupment of specified costs and expenses, would increase to 12.5%,proportionately reduced to the interest conveyed. The Trust’s net profitsinterest burdens the overriding royalty interest reserved by PNR. PNR hasinformed the Trustee that it believes this process is consistent with the termsof the original conveyance and with the handling of other farmout transactionsinvolving lands burdened by the Trust’s net profits interest.

PNR continues to own the undivided one-half interestnot burdened by the Trust’s net profits interest and will participate in andoperate the well as owner of that undivided one-half interest (subject to anagreement with Woodside to grant Woodside such interest in PNR’s remainingundivided one-half interest to equalize those parties participation in thewell).

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

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

***West Delta 61 and62***

| ** **                                                       | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Gross proceeds @  90%                                            |       | $        | 1,929,040  |     | $          | 650,322  |       | $ | 552,153 |   |
| Operating  expenditures @ 90%                                    |       | (20,795  | )          | (1,551   | )          | (176,695 | )          |
| Capital  expenditures @ 90%                                      |       | —   |       | —   |       | (12,829  | )          |
| Net proceeds  (deficit)                                          |       | $        | 1,908,245  |     | $          | 648,771  |       | $ | 362,629 |   |
| Production  Volumes and Average Prices:                          |       |     |       |     |       |     |       |
| Crude oil, condensate and natural gas  liquids (Bbls)  |       | 12,261   |       | 9,596    |       | 7,266    |       |
| Average sales price per Bbl                                      |       | $        | 48.96      |     | $          | 32.55    |       | $ | 27.92 |   |
| Natural gas (Mcf)                                                |       | 185,769  |       | 63,109   |       | 52,401   |       |
| Average sales price per Mcf                                      |       | $        | 7.09       |     | $          | 5.35     |       | $ | 7.26 |   |
| Producing wells                                                  |       | 4        |       | 4        |       | 3        |       |

 

Hurricane Katrina struck theGulf of Mexico in August 2005. PNR notified the Trust that it had receivedpreliminary assessments regarding damages from Hurricanes Katrina to the WestDelta production facilities in which the Trust has an interest. The operator ofthe West Delta properties has informed PNR that the West Delta properties havebeen shut in since August 27, 2005 due to damage to the platform, thepipeline and the sales terminal. The operator has notified PNR that thepipeline has not been repaired and currently there is no estimate as to whenthe repairs will be completed. The operator does not have an estimate on whenproduction at West Delta will resume.

TheWest Delta 61 and 62 blocks experienced an increase in oil and natural gasproduction in 2005 as compared to the same period in 2004 due to productionfrom new wells that came online in the third quarter of 2004. The PNR-operatedwells ceased production in 2002, and the wells were plugged and abandoned byyear-end with the facilities being completely abandoned during 2003. The onlyremaining wells on this block are in West Delta 61. PNR farmed out a portion ofWest Delta 61 to Stone retaining a 12.5% (11.25% net to the Trust) overridingroyalty interest.

***Capital Expenditures***

In 2005, the Trustreceived, from PNR, net proceeds of $375,300 related to the sale of the SouthMarsh Island 155 platform that was abandoned by PNR and for casings related tothe PNR platform at Brazos A-39. PNR does not anticipate any significantcapital expenditures on the Royalty Properties in the future. Due to thelimited financial capacity of the Trust, PNR has advised that it intends tofarm out the 

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Trust’sinterest in the blocks it believes may be produced economically, retaining anoverriding royalty interest for the Trust.

***Abandonment Expenditures***

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 |   |
| Abandonment cost  incurred (Brazos A-7A, A-7#4,A-39A1A,A-2 and A-3A) |   | (2,328,085 | )         |
| Balance,  December 31, 2005                                     |   | $          | 348,066   |   |

 

***Liquidity and Capital 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 futureRoyalty income attributable to the Partnership, of which the Trust has a 99.99%interest.

***Production and Price Review***

Production volumes for natural gas increased to209,697 Mcf in 2005 as compared with 92,254 Mcf in 2004. The average salesprice received for natural gas in 2005 was $7.01 per Mcf as compared with $5.38per Mcf in 2004. Crude oil, condensate and natural gas liquids productionvolumes increased to 12,313 barrels in 2005 as compared to 9,632 barrels in2004. The average sales price in 2005 for crude oil, condensate and natural gasliquids was $48.97 per barrel as compared with $32.57 per barrel in 2004.

Production volumes fornatural gas increased to 92,254 Mcf in 2004 as compared with 88,045 Mcf in2003. The average sales price received for natural gas in 2004 was $5.38 perMcf as compared with $6.05 in 2003. Crude oil, condensate and natural gasliquids production volumes increased to 9,632 barrels in 2004 as compared to7,614 barrels in 2003. The average sales price in 2004 for crude oil,condensate and natural gas liquids was $32.57 per barrel as compared with$27.90 per barrel in 2003.

**Item 7A.**  Quantitative and QualitativeDisclosures About Market Risk.

Not applicable.

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**Item 8.**  Financial Statements andSupplementary Data.

**MESAOFFSHORE TRUSTSTATEMENTS OF DISTRIBUTABLE INCOME**

| ** **                           | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------|------------|---------------------------------------------|------------|
| ** **                           | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| Royalty income                       |       | $                                           | 2,284,914  |   | $ | — |   | $ | — |   |
| Interest income                      |       | 8,512                                       |       | 4,493 |   | 9,169 |   |
| General and  administrative expenses |       | (2,293,426                                  | )          | (4,493 | ) | (9,169 | ) |
| Distributable  income                |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Distributable income per  unit       |       | $                                           | —     |   | $ | — |   | $ | — |   |

 

**STATEMENTSOF ASSETS, LIABILITIES AND TRUST CORPUS**

| ** **                                                                         | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                         | ** ** | **2005**              | ** ** | **2004** | ** ** |
| ASSETS                                                                             |       |                  |       |   |   |
| Cash and short-term  investments                                                   |       | $                     | 1,846,798  |   | $ | 376,599 |   |
| Interest  receivable                                                               |       | 1,582                 |       | 250 |   |
| Net overriding  royalty interest in oil and gas properties                         |       | 380,905,000           |       | 380,905,000 |   |
| Less: accumulated amortization                                                     |       | (380,901,952          | )          | (380,893,873 | ) |
| Total assets                                                                       |       | $                     | 1,851,428  |   | $ | 387,976 |   |
| LIABILITIES AND TRUST CORPUS                                                       |       |                  |       |   |   |
| Reserve for trust  expenses                                                        |       | $                     | 1,848,380  |   | $ | 376,849 |   |
| Distributions  payable                                                             |       | —                |       | — |   |
| Trust corpus  (71,980,216 units of beneficial interest authorized and outstanding) |       | 3,048                 |       | 11,127 |   |
| Total liabilities and  trust corpus                                                |       | $                     | 1,851,428  |   | $ | 387,976 |   |

 

**STATEMENTSOF CHANGES IN TRUST CORPUS**

| ** **                                       | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                       | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| Trust corpus,  beginning of year                 |       | $                                           | 11,127     |   | $ | 11,127 |   | $ | 11,127 |   |
| Distributable  income                            |       | —                                      |       | — |   | — |   |
| Distributions to  unitholders                    |       | —                                      |       | — |   | — |   |
| Amortization of  net overriding royalty interest |       | (8,079                                      | )          | — |   | — |   |
| Trust corpus, end of  year                       |       | $                                           | 3,048      |   | $ | 11,127 |   | $ | 11,127 |   |

 

The accompanying notes are an integral part of thesefinancial statements.

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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 the MesaOffshore Trust Indenture (the “Trust Indenture”) provide, among other things,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 Trustwill terminate upon the first to occur of the following events: (i) thetotal amount of cash received per year by the Trust for each of threesuccessive years commencing after December 31, 1987 is less than ten timesone-third of the total amount payable to the Trustee as compensation for suchthree-year period (the “Termination Threshold”) or (ii) a vote by holdersof a majority of the outstanding units in favor of termination. Amounts earnedby the Trustee as compensation were approximately $204,000 $148,000 and$152,000 for the years 2005, 2004 and 2003, respectively. As described furtherin “Legal Proceedings and Status of the Trust” on page 8 of this Form 10Kand “Timing of Liquidation” on page 10 of this Form 10-K, theTermination 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 non-producingoil 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”). Subsequent tothe 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 owned 99.99% by the Trust and 0.01%by PNR. PNR serves as the managing general partner of the Partnership. PNR receivesno compensation for serving as managing general partner other than the incomeit receives attributable to its interest in the Partnership.

*Legal Proceedingsand Status of the Trust*

HurricaneKatrina struck the Gulf of Mexico in August 2005. PNR notified the Trust thatit had received preliminary assessments regarding damages from HurricaneKatrina to the West Delta production facilities in which the Trust has aninterest. The operator of the West Delta properties has informed PNR that theWest Delta properties have been shut in since August 27, 2005 due todamage to the platform, the pipeline and the sales terminal. The operator hasnotified PNR that the pipeline has not been repaired and currently there is noestimate as to when the repairs will be completed. The operator does not havean estimate on when production at West Delta will resume.

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 of continued declines in production onRoyalty Properties nearing the end of their estimated productive lives, Royaltyincome received by the Trust in 2002, 2003 and 2004 fell below the TerminationThreshold prescribed by the Trust Indenture**. During 2005, theTrustee has taken steps to begin the process of liquidating the Trust. See “__Timingof Liquidation” below in this Note. 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 to participate,as the Trustee expects payment will be required promptly after the close ofbidding without any financing conditions. Accordingly, the auction may not be a“public” auction in the sense that it may not be open to anyone who does notsatisfy these requirements. The Trustee is currently reviewing a potentialonline bidding process for participants in order to provide current publicinformation on bidding to the marketplace. The Trustee will also determine aduration of bidding that it deems in the best interest of the Unitholders.

On April 11, 2005, MOSH Holding, L.P. (MHLP)filed an Original Petition in the District Court of Travis County, Texas, 250thJudicial District, against Pioneer Natural Resources Company; Pioneer NaturalResources USA, Inc.; Woodside Energy (USA), Inc.(Woodside); andJPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (Case No. GN501113).On November 28, 2005, Plaintiff amended its petition. In the amended petition,MHLP asserts claims against Pioneer and Woodside for matters including (1) awrongful farmout of Brazos A-39 by Pioneer, (2) a wrongful delay byPioneer in producing Brazos A-39, (3) fraudulent accountingpractices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aidingand abetting breach of fiduciary duty by Woodside, (6) misapplication ofTrust property by Pioneer, (7) conspiracy to misapply fiduciary propertyby Woodside and Pioneer, (8) common law fraud by Pioneer, (9) grossnegligence by Pioneer, and (10) breach of the conveyance agreement byPioneer. MHLP asserts claims for damages against the Trustee for (a) anaccounting; and (2) breach of fiduciary duty. The plaintiff remedies beingsought include (a) reconstruing the Trust Indenture to determine that theTrust is not terminated because there has or should have been production whichwould have generated revenues to extend the life of the Trust, (b) requiringthe Trustee to pursue certain claims, or to allow plaintiff to pursue such claims,(c) setting aside any farmouts by Pioneer in which there have beenconveyances to an affiliate of Pioneer in violation of the Trust’s Conveyanceand as a self-dealing transaction, (d) removingJPMorgan Chase Bank, N.A. as Trustee; (e) seeking return or forfeiture of 

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compensationto JPMorgan Chase Bank, N.A. (f) recovering monetary damages againstPioneer, Woodside and JPMorgan Chase Bank, N.A., and (g) pursuingexemplary damages against all defendants.

On November 30, 2005 JPMorgan Chase Bank, N.A.announced its intention to resign as Trustee of the Mesa Offshore Trusteeeffective January 31, 2006. Since that announcement, MHLP and others havesought a qualified institution willing to serve as successor Trustee. However,neither MHLP nor Pioneer have identified a willing qualified successor Trusteethat is not also a lender under one of Pioneer’s credit facilities (whichstatus MHLP contends is an alleged conflict of interest).

On Friday, January 27, 2006, a hearing was heldin the 334th Judicial District Court of Harris County,Texas, regarding MHLP’s Verified Application for Emergency Appointment of aTemporary Trustee in Case No. 2006-01984, MOSH Holding, L.P. v.Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc; WoodsideEnergy (USA), Inc.; and JPMorgan Chase Bank, N.A., as Trustee of the MesaOffshore Trust. This case follows the transfer of prior claims filed by theplaintiff in Case No. GN501113. At this hearing, the court declined toapprove MHLP’s motion to appoint Timothy J. Roberson, a principal and affiliateof the plaintiff, as temporary Trustee and declined to appoint any other personas temporary or successor Trustee.

In light of this development, and the absence of an identifiedsuccessor Trustee, JPMorgan Chase Bank, N.A. withdrew its resignation asTrustee. The Trustee continues to desire the appointment of a qualifiedsuccessor Trustee.

To date, the Trustee has allowed MHLP to proceed onthe issue of whether the farmout by Pioneer was a valid farmout, and thelawsuit remains in a phase where the parties are attempting to discoverinformation about the claims and allegations. While Pioneer has provided a reasonedanalysis of why it believes the farmout was in fact valid under the terms ofthe conveyance, only a court, and not the Trustee, can make a finaldetermination. Further, while the plaintiff’s claims on the farmout issue maymerit adjudication, based on facts known to the Trustee at this time, theTrustee is unable to determine, even if the plaintiff prevailed on itsuncertain liability claims, whether the Trust would realize any economicbenefit. Based on information received to date, the Trustee has not concludedthat it would be in the best interest of the unitholders to fund the MHLPclaims directly with Trust funds. However, as noted above, the Trustee has notopposed the plaintiff’s pursuit of its claims on behalf of the unitholders attheir own expense, which reasonable expenses would be subject to repayment ifthe claims proved successful and a benefit were conferred upon all Unitholdersof the Trust. In connection with both the anticipated sale of Trust propertiespursuant to the Trust’s termination and the pending litigation, the Trustee has(1) engaged an independent reserve engineer to review the estimatedreserves and (2) had an independent joint venture auditor review certainhistorical expenditures and revenue receipts on Trust properties. The Trusteebelieves expenditures for these reviews were prudent and in the interest of theunitholder.

The Trustee will make the full detail of theunderlying data of the December 31, 2005 reserve report available for usein connection with the sale of the Trust properties as part of the Trusttermination. For more information regarding the estimated remaining life ofeach of the Royalty Properties, the estimated future net revenues of theRoyalty Properties and information relating to farm-outs of interests on theRoyalty Properties based on information provided by PNR to D&M , see pages 22and 23 of this Form 10-K and Note 6 in the Notes to FinancialStatements included elsewhere in this Form 10-K. The sale of theassets of the Trust estate will include the related rights to abandonmentaccruals made by PNR. As explained in “Regulation and Prices—PlatformAbandonment and Removal” on page 26 of this Form 10-K and Note 3in the Notes to the Financial Statements included elsewhere in thisForm 10-K, PNR withholds from the Trust a reserve to cover its share ofthose future abandonment and removal costs. To the extent a certain party isable to complete the abandonment for an amount less than the funds withheld byPNR, the related rights to the abandonment accrual are likely to be deemedmarketable. The final distribution to unitholders will be an amount net offunds required to satisfy all Trust liabilities.

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*Timing ofLiquidation*

In connection with this litigation, the Trustee hasagreed that it will give MHLP at least 60 days notice prior to the sale of anyTrust properties in connection with the termination of the Trust. As of thedate of this filing, based on the information currently provided by Pioneer andthe preliminary state of the proceeding, the Trustee has not made anydefinitive conclusions as to the validity of the claims asserted by MHLP.However, the review of reserves by the independent reserve engineer has notshown the existence of significant reserves not previously included in thereserve report prepared by Pioneer in quantities originally alleged in theplaintiff’s petition. Due to the pending litigation, the Trustee cannot predictthe timing of the sale of all or a portion of the Trust properties as part ofthe Trust Termination.

As part of the termination procedures, the Trusteeengaged an independent joint venture auditor in October 2004 to review theTrust properties as part of the termination of the Trust. The joint ventureauditor reviewed the periods from 2003 through 2004. The Trustee believed thisengagement of an outside party on these matters to be a prudent step toidentify any potential benefits to the Trust, as well as any limitations onpotential benefits, due to differing interpretations of accounting matters thatcommonly occur in the oil and gas production industry. The review of theindependent joint venture auditor was completed in December 2005, and itwas the joint venture auditor’s opinion that the charges and credits andrevenue to the Trust were in accordance with the applicable agreements, exceptfor certain items noted in the report. The report notes exceptions which may ormay not turn out to be meritorious, as to amounts due to the Trust of $204,219.PNR, Stone Energy (Stone) and Newfield Exploration Company (Newfield) have received a copy of the report andhave 180 days to respond to these findings. As of March 15, 2006, PNR,Stone and Newfield have not yet responded to the findings in this report. Anyproceeds received as a result of the joint venture audit will be included asRoyalty income in the period in which the proceeds are received.

**(2)**   NetOverriding 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 the Royalty, which is calculated onthe basis of current royalty income in relation to estimated future royaltyincome, is charged directly to trust corpus since such amounts do not affectdistributable income.

**(3)**   Basisof Accounting

The financial statementsof 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;

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

(c)   Trust general and administrative expenses are recorded in themonth they accrue and are recoupable from Royalty income.

This basis for reportingdistributable income is considered to be the most meaningful becausedistributions to the unitholders for a month are based on net cash receipts forsuch month. However, it will differ from the basis used for financialstatements prepared in accordance with accounting principles generally acceptedin the United States of America because, under such accounting principles,royalty income for a month would be based on net proceeds from production forsuch month without regard to when calculated or received and interest incomefor a month would be calculated only through the end of such month.

The instruments conveyingthe Royalty provide that the working interest owner will calculate and pay thePartnership each month an amount equal to 90% of the net proceeds for thepreceding month. Generally, net proceeds means the excess of the amountsreceived by the working interest owner from sales of oil and gas from theRoyalty Properties plus other cash receipts over operating and capital costsincurred. For the twelve months ending December 31, 2004, operating andcapital costs incurred exceeded proceeds from oil and gas sales; accordingly,no Royalty income was reported.

For the twelve months ended December 31, 2005,the Trust had Royalty income of $2,284,914. However, no Royalty income will bedistributed to unitholders until the Trustee recoups Trust expenses being paidfrom the reserve that the Trustee has established for anticipated futuregeneral and administrative expenses. As of December 31, 2005, $151,620will be recouped by the Trustee from future Royalty income before Trustdistributions will resume. The unexpended amount withheld by PNR for future abandonmentcosts at December 31, 2005 was $348,066.

**Assets and Liabilities in the Process of Liquidation**

As a result of the contractual termination of theTrust effective January 1, 2005, the Trust is in the process ofliquidation. The below table presents the assets of the Trust at theirestimated fair value:

| ** **                                                | ** ** | **December 31,  2005** | ** ** |
|-----------------------------------------------------------|------------|-----------------------------|------------|
| ASSETS                                                    |       |                        |       |   |   |
| Cash and short term investments                           |       |                        | $          | 1,846,798 |   |   |
| Interest receivable                                       |       |                        | 1,582      |   |   |
| Net overriding royalty interest in oil and gas properties |       |                        | 4,831,237  |   |   |
| Total assets                                              |       |                        | 6,679,617  |   |   |
| LIABILITIES                                               | ** ** |                        |       |   |   |
| Reserve for Trust expenses                                |       |                        | $          | 1,848,380 |   |   |
| Total liabilities                                         |       |                        | 1,848,380  |   |   |
| Net  assets in process of liquidation                     |       |                        | $          | 4,831,237 |   |   |

 

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The net overriding royalty interest in oil and gas properties at December 31,2005 reflect the Trustee’s estimate of value, (in the absence of third-partyappraisals or evaluations) based on the Trust’s share of future net revenuesfrom the net overriding royalty interest in the properties as ofDecember 31, 2005. This estimate is based on the Trustee’s currentassessment of the impact of selling existing assets based on current marketconditions, and includes the following assumptions:

·  TheTrust’s estimated share of oil and gas reserve volumes at December 31,2005, were derived from the reserve report prepared by DeGolyer and MacNaugton(D&M). The Trust’s estimated share of oil and gas reserve volumes atDecember 31, 2005 include reserves related to the Midway Prospect.(1)

·  Forwardstrip commodity prices on December 31, 2005 for the life of the reserves.

·  Exclusionof estimated future abandonment costs.(2)

·  Discountrate of 10%.

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(1)   As a result of the litigation described above, the Trust had beenunable to obtain necessary information from the working interest owner regardingsuch owner’s own current estimate of the fair value of the proved reserves onthe Midway Prospect. The Trustee engaged D&M, an independent reserveengineer, to review all oil and gas reserves pertaining to the Royalty,including the Midway Prospect reserves and the Trust’s interest in thesereserves as of December 31, 2005.

(2)   The sale of the assets currently owned by the Partnership willinclude the related rights to abandonment costs previously withheld by theworking interest owner. The working interest owner has withheld funds to coverthe Trust’s share of future abandonment and removal costs. To the extent the abandonmentis completed for an amount less than the funds withheld by the working interestowner those funds would be distributed to the Trust. Therefore, estimatedfuture abandonment costs are not reflected as a reduction of future netrevenue.

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

Forall other assets presented in the above table, the Trustee believes thathistorical cost approximates fair market value due to the short-term nature ofsuch assets. The Trustee will continue to reserve funds to recoup itspreviously established reserves to pay Trust expenses, which will primarilyconsist of expenses incurred by the Trustee to liquidate the Trust’s assets.Any funds remaining after all expenses have been paid will be distributed tothe Unitholders.

**(4)**   Distributions to Unitholders

Under the terms of the Trust Indenture, the Trusteemust distribute to the unitholders all cash receipts, after paying liabilitiesand providing for cash reserves as determined necessary by the Trustee. Theamounts distributed are determined on a monthly basis and are payable tounitholders of record as of the last business day of each month. However, cashdistributions are made quarterly in January, April, July and October, andinclude interest earned from the monthly record dates to the dates ofdistribution.

**(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 

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identical facts andcircumstances. It is possible, therefore, that the IRS would assert upon auditthat the Trust is taxable as a corporation and that a court might agree withsuch assertion.

As agrantor trust, the Trust will incur no federal income tax liability. Inaddition, it will incur little or no federal income tax liability if it is heldto be a non-grantor trust. If the Trust were held to be taxable as acorporation, it would have to pay tax on its net taxable income at thecorporate rate.

**(6)**   SupplementalReserve Information (Unaudited)

Estimates of the proved oil and gas reservesattributable to the Royalty as of December 31, 2005, are based on a reportprepared by DeGolyer and MacNaughton (D&M). The 2004 and 2003 reports 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 areallocated based on royalty income. Because the net reserve volumes attributableto the Partnership interest are estimated using an allocation of reservevolumes based on estimates of future net revenue, a change in prices or costswill result in changes in the estimated net reserve volumes. Therefore, theestimated net reserve volumes attributable to the Partnership interest willvary if different future price and cost assumptions are used. Only costsnecessary to develop and produce existing proved reserve volumes were assumedin the allocation of reserve 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.

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.

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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, 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 |   |
| Revisions of previous estimates             |       |                         | 16,613     |             |       | 326,093 |   |
| Extensions, discoveries and other additions |       |                         | 507        |             |       | 169,150 |   |
| Production                                  |       |                         | (12,314    | )                |       | (209,698 | ) |
| December 31, 2005                      |       |                         | 10,766     |             |       | 460,055 |   |
| Proved Developed  Reserves:                 |       |                         |       |             |       |   |   |
| December 31, 2002                      |       |                         | 16,661     |             |       | 432,442 |   |
| December 31, 2003.                     |       |                         | 11,111     |             |       | 432,679 |   |
| December 31, 2004.                     |       |                         | 5,960      |             |       | 174,510 |   |
| December 31,  2005.                    |       |                         | 10,766     |             |       | 460,055 |   |

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(See Notes on following page.)

**StandardizedMeasure of Future Royalty Income fromProved Oil and Condensate and Gas Reserves, Discounted at 10% Per Annum(Unaudited)**

| ** **                                                                      | ** ** | **December 31,**   | ** ** |
|---------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                      | ** ** | **2005**                | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                      | ** ** | **(In thousands)** | ** ** |
| Ninety percent of  future gross proceeds                                        |       | $                       | 4,625      |   | $ | 1,808 |   | $ | 3,584 |   |
| Less ninety percent of—                                                    |       |                    |       |   |   |   |   |
| Future operating costs                                                          |       | (65                     | )          | (469 | ) | (640 | ) |
| Future capital costs, net of amounts previously  accrued                        |       | —                  |       | — |   | — |   |
| Deficit due PNR                                                                 |       | —                  |       | (59 | ) | (697 | ) |
| Future Royalty  income                                                          |       | 4,560                   |       | 1,280 |   | 2,247 |   |
| Discount at 10%  per annum                                                      |       | (738                    | )          | (176 | ) | (674 | ) |
| Standardized measure of  future Royalty income from proved oil and gas reserves |       | $                       | 3,822      |   | $ | 1,104 |   | $ | 1,573 |   |

 

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**Changesin the Standardized Measure of Future Royalty Income fromProved Oil and Gas Reserves, Discounted at 10% Per Annum (Unaudited)**

| ** **                                  | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                  | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                  | ** ** | **(In thousands)**                     | ** ** |
| Standardized  measure at beginning of year  |       | $                                           | 1,104      |   | $ | 1,573 |   | $ | 1,670 |   |
| Revisions of previous estimates             |       | 3,311                                       |       | (752 | ) | (675 | ) |
| Net changes in prices and production costs  |       | 422                                         |       | 126 |   | 411 |   |
| Extensions, discoveries and other additions |       | 1,160                                       |       | — |   | — |   |
| Royalty income                              |       | (2,285)                                     |       | — |   | — |   |
| Accretion of discount                       |       | 110                                         |       | 157 |   | 167 |   |
| Net changes in standardized measure         |       | 2,718                                       |       | (469 | ) | (97 |   |
| Standardized measure at  end of year        |       | $3,822                                      |       | $ | 1,104 |   | $ | 1,573 |   |
|                                             |            |                                             |            |  |  |  |  |  |  |  |

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·                     The estimatedquantities of proved reserves, standardized measure of future Royalty incomeand changes in the standardized measure represent 100% of amounts for thePartnership 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** | ** ** |
| 2005:                          |       |                                       |       |   |   |   |   |   |   |   |   |
| Royalty income                 |       | $                                          | 173,460    |   | $ | 505,409 |   |   | $ | 288,534 |   |   | $ | 1,317,512 |   |
| Distributable  income          |       | $                                          | —     |   | $ | — |   |   | $ | — |   |   | $ | — |   |
| Distributable  income per unit |       | $                                          | —     |   | $ | — |   |   | $ | — |   |   | $ | — |   |
| 2004:                          |       |                                       |       |   |   |   |   |   |   |   |   |
| Royalty income                 |       | $                                          | —     |   | $ | — |   |   | $ | — |   |   | $ | — |   |
| Distributable  income          |       | $                                          | —     |   | $ | — |   |   | $ | — |   |   | $ | — |   |
| Distributable income per  unit |       | $                                          | —     |   | $ | — |   |   | $ | — |   |   | $ | — |   |

 

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**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

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 31,2005 and 2004, and the related statements of distributable income and changesin trust corpus for each of the years in the three-year period ended December 31,2005. 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 the standardsof the Public Company Accounting Oversight Board (United States). Thosestandards 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, 2005 and 2004, andthe distributable income and changes in trust corpus for each of the years inthe three-year period ended December 31, 2005, 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. The Trust Indenture provides the Trustee a two-year period during whichit must sell all of the Trusts properties. Accordingly, there existssubstantial doubt about the Trust’s ability to continue as a going concern. Thefinancial statements do not include any adjustments that might result from theoutcome of this uncertainty.

**KPMG LLP**

Houston, TexasMarch 31, 2006

 

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

None.

**Item 9A.**                Controlsand Procedures

*Evaluationof Disclosure Controls and 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 end of the period covered by this report,the Trustee carried out an evaluation of the Trust’s disclosure controls andprocedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded thatthe controls and procedures are effective.

Due to the contractual arrangements of (i) theTrust Indenture, (ii) the Partnership Agreement and (iii) the rightsof the Partnership under the Conveyance regarding information furnished by theworking interest owners, the Trustee relies on: (A) information provided by the working interest owners, including (i) thestatus of litigation, (ii) historical operating data, plans for futureoperating and capital expenditures, reserve information, as well as (iii) informationrelating to projected production; (B) information provided by the managinggeneral partner of the Partnership that is collected by the managing generalpartner from the working interest owners; and (C) conclusions regardingreserves by reserve engineers or other experts in good faith. See Item 1A. RiskFactors “—None of the Trust nor its unitholders control the operation ordevelopment of the Royalty Properties and have little influence over operationor development” and “—The Trustee relies upon the working interest owners andmanaging general partner for information regarding the Royalty Properties” inthis form 10-K for a description of certain risks relating to thesearrangements and reliance.

*Changesin Internal Control over Financial Reporting..**  *In connection with the evaluationby the Trustee of changes in internal control over financial reporting of theTrust that occurred during the Trust’s last fiscal quarter, no change in theTrust’s internal control over financial reporting was identified that hasmaterially affected, or is reasonably likely to materially affect, the Trust’sinternal control over financial reporting. The Trustee notes for purposes ofclarification that it has no authority over, has not evaluated and makes nostatement concerning, the internal control over financial reporting of theworking interest owners or the managing general partner of the Partnership.

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**PART III**

**Item 10.**                 Directorsand Executive 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.                                          |       |                                                                  | 7,332,887  | (2)(3)                         |       |   | 10.2 | % |   |
|                                                               |       | Nine  Greenway Plaza                                              |       |                                                                  |       |                           |       |   |   |   |   |
|                                                               |       | Suite 3040                                                   |       |                                                                  |       |                           |       |   |   |   |   |
|                                                               |       | Houston,  Texas 77046                                             |       |                                                                  |       |                           |       |   |   |   |   |

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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 (“MHLP”). MOSH Holding I, L.L.C., a Texas limitedliability company (“MOSHLLC”) is the sole general partner of MHLP and has soleinvestment 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.

See Item 3. Legal Proceedingsand Item 1. Business “—Legal Proceedings and Status of the Trust” and “—Timingof Liquidation” for a description of legal proceedings and related transactionsamong the Trustee, the Trust and a 10% beneficial owner of units of the Trust.

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**Item 14.**                 PrincipalAccounting 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.

The following table presents fees for professionalaudit services rendered by KPMG LLP for the audit of the Mesa Offshore Trustfinancial statements for 2005 and 2004 and fees billed for other servicesrendered by KPMG LLP.

| ** **          | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------|------------|----------|------------|----------|------------|
| Audit fees(1)       |       | $        | 100,000    |     | $          | 90,000 |   |
| Audit-related  fees |       | —   |       | —   |       |
| Tax fees(2)         |       | 25,000   |       | 25,000   |       |
| All other fees      |       | —   |       | —   |       |
| Total fees          |       | $        | 125,000    |     | $          | 115,000 |   |

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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)          Taxfees consist of fees related to the Mesa Offshore Trust’s tax information forits unitholders paid in 2005 related to 2004 tax work and paid in 2004 relatedto 2003 tax work.

**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                                     |       |                                       | 39         |   |   |
| Statements of Assets, Liabilities and Trust Corpus                     |       |                                       | 39         |   |   |
| Statements of Changes in Trust Corpus                                  |       |                                       | 39         |   |   |
| Notes to Financial Statements                                          |       |                                       | 40         |   |   |
| Report of Independent Registered Public Accounting  Firm—KPMG LLP |       |                                       | 49         |   |   |

 

**(a)(2)   Schedules**

Schedules have been omitted because they are notrequired, not applicable or the information required has been includedelsewhere herein.

**(a)(3)**   Exhibits

(JPMorgan Chase Bank, N.A., is successor by mergers tothe original name of the Trustee, Texas Commerce Bank National Association)

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| ** ** | ** ** | ** **                                                                                                                                                                                                                                                                                                        | ** ** | **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 31, 2006 | * *            | * * |

 

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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**EXHIBIT INDEX**

| **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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