**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

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**FORM 10-K/A**

**Amendment No. 1**

| **(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, 2006** |
| **o**                                                | ** ** | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934** |

 

**FORTHE TRANSITION PERIODFROM            TO             **

**Commissionfile number 1-8432**

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**Mesa Offshore Trust**

(Exact Name of Registrantas Specified in Its Charter)

| **Texas**                                 |   | **76-6004065**       |
|-------------------------------------------|--------|----------------------|
| (State or Other  Jurisdiction of          |   | (I.R.S. Employer     |
| Incorporation or  Organization)           |   | Identification  No.) |
| **JP Morgan Chase Bank, N.A., Trustee**   |   |                 |
| **Institutional  Trust Services**         |   |                 |
| **919  Congress Avenue, Austin, Texas**   |   | **78701**            |
| (Address of  Principal Executive Offices) |   | (Zip Code)           |

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

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

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

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

**Units of beneficialinterest**

(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 or Section 15(d) ofthe 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 past 90 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 |
|--------------------------------|--------------------------|------------------------------|

 

Indicateby check mark whether the registrant is a shell company (as defined in Rule 12b-2of 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, 2006, of $0.12 wasapproximately $8,637,626.

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, 2007, 71,980,216 Units ofBeneficial Interest were outstanding in Mesa Offshore Trust.

DOCUMENTSINCORPORATED BY REFERENCE: **None.**

 

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**TABLEOF CONTENTS**
|            | ** ** | ** **                                                                                                             | ** ** | **Page** | ** ** |
|------------|------------|------------------------------------------------------------------------------------------------------------------------|------------|----------|------------|
|       | ** ** | **PART I**                                                                                                        |       |     |       |   |   |
| Item 1.    |       | Business                                                                                                               |       |     | 4          |   |   |
|       |       | Description of the Trust                                                                                               |       |     | 4          |   |   |
|       |       | Description of the Units                                                                                               |       |     | 6          |   |   |
|       |       | Legal Proceedings and Status of the Trust                                                                              |       |     | 8          |   |   |
|       |       | Timing of Liquidation                                                                                                  |       |     | 12         |   |   |
|       |       | Description of Royalty Properties                                                                                      |       |     | 14         |   |   |
|       |       | Contracts                                                                                                              |       |     | 24         |   |   |
|       |       | Regulation and Prices                                                                                                  |       |     | 25         |   |   |
| Item  1A.  |       | Risk  Factors                                                                                                          |       |     | 27         |   |   |
| Item 1B.   |       | Unresolved Staff Comments                                                                                              |       |     | 31         |   |   |
| Item 2.    |       | Properties                                                                                                             |       |     | 31         |   |   |
| Item  3.   |       | Legal  Proceedings                                                                                                     |       |     | 31         |   |   |
| Item 4.    |       | Submission of Matters to a Vote of Security Holders                                                                    |       |     | 31         |   |   |
|       | ** ** | **PART II**                                                                                                       |       |     |       |   |   |
| Item 5.    |       | Market for the Registrant’s  Common Equity, Related Unitholder Matters and Issuer Purchases of Equity  Securities |       |     | 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                                                            |       |     | 39         |   |   |
| 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**                                                                                                      |       |     |       |   |   |
| Item 10.   |       | Directors, Executive  Officers and Corporate Governance                                                                |       |     | 51         |   |   |
| Item 11.   |       | Executive Compensation                                                                                                 |       |     | 51         |   |   |
| Item 12.   |       | Security Ownership of  Certain Beneficial Owners and Management and Related Unitholder Matters     |       |     | 51         |   |   |
| Item 13.   |       | Certain Relationships and  Related Transactions, and Director Independence                                             |       |     | 52         |   |   |
| Item 14.   |       | Principal Accounting Fees and Services                                                                                 |       |     | 52         |   |   |
|       | ** ** | **PART IV**                                                                                                       |       |     |       |   |   |
| Item 15.   |       | Exhibits, Financial Statement Schedules                                                                                |       |     | 52         |   |   |
| SIGNATURES |       |                                                                                                                   | 54         |     |       |

 

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**EXPLANATORY NOTE**

This Amendment No. 1 on Form 10-K/A amends theRegistrant’s Annual Report on Form 10-K, as filed by the Registrant with theSecurities and Exchange Commission on March 28, 2007, and is being filedsolely: (1) to correct the date of the reserve letter on page 22 to April 10,2007, (2) to delete the final sentence of the third paragraph of Note 3 of thefinancial statements on page 45 relating to 2004 operating and capital costs,and (3) to correct the amount of future general administrative costs andexpenses on page 47 to $1,200,000 as described elsewhere in the Form 10-K.

**Note RegardingForward-Looking Statements**

This Form 10-K includes “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934,as amended. All statements other than statements of historical facts includedin this Form 10-K, including without limitation the statements under“Business—Termination of the Trust,” “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations” and Note 1 to the financialstatements of the Trust regarding the future net revenues of the Trust, areforward-looking statements. Although Pioneer Natural Resources Company (“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 THETRUST**

The Mesa Offshore Trust (the “Trust”), created underthe laws of the State of Texas, maintains its offices at the office of theTrustee, JPMorgan Chase Bank, N.A. (the “Trustee” or “JPMorgan’’), 919 CongressAvenue, Austin, Texas 78701. The telephone number of the Trust is 1-800-852-1422.JPMorgan Chase Bank, N.A. was formerly known as The Chase Manhattan Bank and isthe successor by mergers to the original name of the Trustee, Texas CommerceBank National 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” beginning on page 8 of this Form 10-K and “—Timingof Liquidation” beginning on page 12 of this Form 10-K foradditional information regarding PNR and the Trust.

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

The terms of the Mesa Offshore Trust Indenture (the “TrustIndenture”) provide, among other things, that: (1) the Trust cannotacquire any asset other than its interest in the Partnership and cannot engagein any business or investment activity; (2) the Royalty can be sold inpart or in total for cash upon approval of the unitholders or upon terminationof the Trust; (3) the Trustee can establish cash reserves and borrow fundsto pay liabilities of the Trust and can pledge the assets of the Trust tosecure payment of the borrowing; (4) the Trustee will make quarterlydistributions of cash available for distribution to the unitholders in January,April, July and October of each year; and (5) the Trust willterminate upon the first to occur of the following events: (i) the totalamount of cash received per year by the Trust for each of three successiveyears commencing after December 31, 1987 is less than ten times one-thirdof the total amount payable to the Trustee as compensation for such three-yearperiod (the “Termination Threshold”) or (ii) a vote by holders of amajority of the outstanding units in favor of termination. Amounts paid to theTrustee as compensation were approximately $360,000, $204,000 and $148,000, forthe years 2006, 2005 and 2004, respectively. As described further in “—LegalProceedings and Status of the Trust” beginning on 

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page 8 of this Form 10-K,the Termination Threshold was met in each of the three consecutive years endingDecember 31, 2004. Upon termination of the Trust, the Trustee will sellfor cash all the assets held in the Trust estate and make a final distributionto unitholders of any funds remaining after all Trust liabilities have beensatisfied.

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 14 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 under thecircumstances. See “Contracts” on page 24 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 in theirentirety by reference to the Trust Indenture, the Partnership Agreement and theConveyance themselves, which are exhibits to this Form 10-K and areavailable 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 THEUNITS**

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 theMonthly Record Date to the payment date.

**Liability ofUnitholders**

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

**Federal Income TaxMatters**

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

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

*Ownership of Units*

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

*Income andDepletion*

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

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

*Backup Withholding*

Distributions from theTrust are generally subject to backup withholding at a rate of 28% of these distributions.Backup withholding will not normally apply to distributions to a unitholder,however, unless the unitholder fails to properly provide to the Trust histaxpayer identification number or the IRS notifies the Trust that the taxpayeridentification 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 similar provisionsof applicable treaties. Upon making this election a unitholder is entitled toclaim all deductions with respect to that income, but he must file aUnited States federal income tax return to claim these deductions. Thiselection once made is irrevocable unless an applicable treaty allows theelection to be made annually.

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

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

*Tax-ExemptOrganizations*

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

**LEGAL PROCEEDINGSAND STATUS OF THE TRUST**

*HurricaneOperations Update*

Hurricane Katrina**struck the Gulf of Mexico in August 2005.PNR has notified the Trust of its current assessments regarding damages fromHurricanes Katrina and Rita to production facilities for properties in whichthe Trust has an interest. The operator of the West Delta properties has informedPNR that the West Delta properties have been shut in since August 27, 2005due to damage to the platform, the pipeline and the sales terminal. Theoperator has notified PNR that they expect production at West Delta to resume duringthe second quarter of 2007.

*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 Item 1. 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, 

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but, asis customary, access to information and participation may be limited to personswho execute confidentiality agreements regarding information provided by theworking interest owners. The Trustee may also require bidders to identifythemselves clearly and to represent or evidence sufficient financing in orderto participate, as the Trustee expects payment will be required promptly afterthe close of bidding without any financing conditions. Accordingly, the auctionmay not be a “public” auction in the sense that it may not be open to anyonewho does not satisfy these requirements. The Trustee is currently reviewing apotential online bidding process for participants in order to provide currentpublic information on bidding to the marketplace. The Trustee will alsodetermine a duration of bidding that it deems in the best interest of theUnitholders.

*Legal Proceedings*

On April 11, 2005, MOSH Holding, L.P. (“MHLP”) filedan Original Petition in the District Court of Travis County, Texas, 250thJudicial District, against Pioneer Natural Resources Company (“PNR”); PioneerNatural Resources USA, Inc. (together with PNR, “Pioneer”); Woodside Energy(USA), Inc. (“Woodside”); and JPMorgan Chase Bank, N.A., as Trustee of the MesaOffshore Trust (Case No. GN501113) (the “Lawsuit”). The Lawsuit is currentlybefore the 334th Judicial District of Harris Country, Texas (the “Court”). MHLP’sOriginal Petition alleges Pioneer and Woodside are liable for various actions,including (1) a wrongful farmout by Pioneer to Woodside of the Brazos A-39Lease, (2) a wrongful delay by Pioneer in producing the Brazos A 39 Lease andthe Midway #5 well drill thereon, (3) fraudulent accounting practices byPioneer, (4) breach of fiduciary duty by Pioneer, (5) aiding and abettingbreach of fiduciary duty by Woodside, (6) misapplication of Trust property byPioneer, (7) conspiracy to misapply fiduciary property by Woodside and Pioneer,(8) common law fraud by Pioneer, (9) gross negligence by Pioneer, and (10)breach of the conveyance agreement by Pioneer. As described below, MHLP lateradded claims against the Trustee for (1) an accounting, and (2) breach offiduciary duty. The remedies MHLP seeks include (a) reconstruing the TrustIndenture to determine that the Trust is not terminated because there has orshould have been production that would have generated revenues to extend thelife of the Trust, (b) requiring the Trustee to pursue certain claims, or toallow MHLP to pursue such claims, (c) setting aside any farmouts by Pioneer inwhich there have been conveyances to an alleged affiliate of Pioneer, (d) theremoval of JPMorgan as Trustee, (e) the return or forfeiture of compensation toJPMorgan, (f) monetary damages against Pioneer, Woodside and JPMorgan, and (g)unspecified exemplary damages against all defendants.

MHLP’s Original Petition did not contain any claimsagainst the Trustee, except to enjoin the Trustee from terminating the Trustduring the pendency of the Lawsuit. In April 2005, the Trustee voluntarilyentered into an agreement with MHLP whereby the Trustee would not terminate theTrust without first giving MHLP at least sixty days written notice. This agreementallowed MHLP time to obtain documents and discovery from Pioneer and Woodside,and allowed the Trustee time to investigate the claims asserted by MHLP againstPioneer and Woodside to determine if they had any merit and, most importantly,whether they would benefit the Trust. During the six month period between Apriland October 2005, the Trustee conducted an independent investigation including:numerous meetings and discussions with the parties; reviewing the relevantdocuments with the Trustee’s counsel; employing independent reservoir engineersto evaluate the reserves in which the Trust has an interest; engagingindependent joint venture auditors to examine the accounting records of theoperator, Pioneer, relating to revenues and expenses allocated to thePartnership’s interests; and obtaining from both MHLP and Pioneer theirrespective legal analyses of the challenged farmout.

Throughout 2005, the parties also anticipated that theMidway #5 well on the Brazos A-39 Lease that is the primary subject of theLawsuit would go into production. Given the vast discrepancy between thereserves claimed by the MHLP and those projected by Pioneer for the Midway #5well, actual production results would significantly impact the Trustee’sassessment of whether the Trust was better off with the 

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cost-free override createdby the Pioneer/Woodside farmout, or the prior cost-burdened net profitsinterest that MHLP seeks to restore through the Lawsuit. Unfortunately,Hurricane Katrina struck the Gulf of Mexico in August 2005 and delayed thecommencement of production until 2006.

Faced with this post-Katrina situation, the Trusteeurged all the parties to consent to a bifurcated trial of the farmout issue onan expedited basis. The Trustee proposed to MHLP that if the Court determinedthat the farmout was not valid and that restoring the net profit interest wouldbenefit the Trust, then the Trust would reimburse MHLP’s reasonable attorneys’fees, up to $100,000, and the Trustee would allow MHLP’s counsel to representthe Trust in prosecuting the damages portion of the case. Conversely, if MHLPwere to lose on the expedited determination of the farmout issue, and in theabsence of more evidence to support any ancillary claims, then MHLP woulddismiss the other claims and would not be reimbursed, and the Trustee wouldmove forward to terminate the Trust.

While the Trustee, Pioneer, and Woodside all agreed toan expedited trial of the farmout issues, MHLP balked. Contrary to theassertions of MHLP and the Intervenor Plaintiffs identified below, the Trusteenever agreed that the claims asserted by MHLP against Pioneer and Woodside “hadmerit” – the Trustee simply stated that the farmout issue might meritadjudication at that time to determine (1) if MHLP was legally correct, and (2)if setting aside the farmout would benefit the Trust.

When MHLP refused to agree to an expedited andbifurcated trial as proposed by the Trustee, the Trustee informed MHLP that theTrustee’s investigation of MHLP’s allegations beyond the farmout issues failedto convince the Trustee of either their merit or that pursuing those claims andincurring the related legal fees and expenses would benefit the Trust. Moreover,the Trustee informed MHLP that the Trustee’s independent joint venture auditorsand reservoir engineers had not found any evidence to date to support any ofMHLP’s allegations.

It was at this point, in November 2005, in the midstof the Trustee’s negotiations with MHLP to obtain an agreed adjudication ofMHLP’s claims, that MHLP alleged for the first time that the Trustee had aconflict of interest because of JPMorgan’s long-standing lending relationshipwith Pioneer. Although it is clear under the Trust Indenture, the Texas TrustAct, and relevant case law that JPMorgan is not precluded, by holding theposition of Trustee, from pursuing commercial banking activities not involvingTrust funds, MHLP amended its petition and asserted claims against the Trusteeon November 28, 2005.

Although MHLP’s claims against the Trustee weremeritless, to avoid any further assertion that the Trustee could notimpartially evaluate MHLP’s claims, on November 30, 2005, JPMorgan announcedits intention to resign as Trustee, effective January 31, 2006. On December 13,2005, the lawsuit was transferred to the 334th Judicial District Court ofHarris County, Texas. At a hearing on January 27, 2006 in the Harris CountyCourt, the Court denied MHLP’s motion for a temporary injunction to removeJPMorgan as Trustee and appoint a principal of MHLP, Timothy Roberson, as a temporaryTrustee. At the Court’s suggestion, JPMorgan agreed to continue as Trustee,until such time as a substitute trustee was found that fulfilled thequalifications of Trustee stated in the Trust Indenture. Since that hearing,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 December 8, 2006, Dagger-Spine Hedgehog Corporation(“Dagger-Spine”) filed a petition to intervene in the Lawsuit as a Plaintiff,alleging claims virtually identical to MHLP. Another group of unitholders, ledby Keith A. Wiegand, (together with Dagger-Spine, the “Intervenors”) also filedon March 9, 2007 a petition to intervene as plaintiffs in the Lawsuit,incorporating and adopting the same claims asserted by MHLP.

On January 26, 2007, the Trustee reached a conditionalsettlement of the claims asserted by MHLP and the Intervenors against Pioneerand Woodside. The conditional settlement is set forth in the Mutual Release andSettlement Agreement dated as of January 26, 2007 (the “Conditional Settlement 

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Agreement”). The Trusteefiled a motion for approval of the Conditional Settlement Agreement with theCourt on January 30, 2007.

The Conditional Settlement Agreement is the product ofextensive investigations and negotiations by the Trustee. In 2006, after theCourt denied MHLP’s attempt to remove JPMorgan as Trustee, the parties pursuedformal discovery in the Lawsuit. During this period, the Trustee continued toevaluate the merits of the alleged claims against Pioneer and Woodside. Acentral allegation by MHLP and the Intervenors is that Pioneer and Woodsidedelayed the commencement of production from the well drilled pursuant to thePioneer-Woodside Farmout – the Midway #5 well on the Brazos A-39 Lease. Woodsideand Pioneer witnesses have given sworn testimony in depositions about thecommercial and technical reasons for the delays in bringing the well on line. Thewell commenced production in April 2006. After this time, the Trusteeinstructed its independent petroleum reserve engineers to evaluate how theproduction results and projected production from the well might affect thevalue of the Trust’s interests. The Trustee’s independent engineers determinedthat the initial data regarding projected production from the well did notwarrant a material change in prior assessments of the value of the Trust’sassets.

Pioneer subsequently reported to the Trustee thatproduction from the well was suspended in July 2006 due to mercurycontamination identified at downstream facilities where the production from thewell is commingled with production from other wells. An updated evaluation fromthe Trustee’s independent petroleum reserve engineers estimated that revenuesfrom future production from the well likely would not exceed the costs ofdrilling and completing the well. Accordingly, if the Partnership’s interest inthe underlying lease had remained, or was, a cost-burdened net profitsinterest, instead of the cost-free overriding royalty interest the Partnershipheld as a result of the Pioneer-Woodside Farmout, the Partnership would nothave received, or would not receive, any payments from this production, and theTrust accordingly would not have received any associated distributions. Further,the production data did not support reserves of the size asserted by MHLP andthe Intervenors. The well resumed production in February 2007.

Under the Conditional Settlement Agreement, Pioneerhas agreed to assign to the Trust an interest confirming its right to a 4.5%cost-free overriding royalty interest in the Brazos A-39 Lease until payout ofthe Midway #5 well, and to assign to the Trust an interest in the Brazos A-39Lease, to be effective from and after payout if payout occurs, equal to a 45%net profits interest. Pioneer would also agree to pay for and satisfyapproximately $1.4 million of plugging, abandonment, and decommissioning costs relatingto several of the assigned Royalty Properties that Pioneer has informed theTrustee would otherwise be allocated to the Partnership’s Royalty. Finally,Pioneer and the Trustee have agreed that Pioneer shall arrange for the sale ofall assets of the Partnership as provided for under the Trust Indenture on, oras soon as practical after, July 1, 2007, or on an earlier date as set forth inthe proposed settlement. The Conditional Settlement Agreement, if approved bythe Court, would settle all claims in the Lawsuit that the Trust or thePartnership has or might have against Pioneer and Woodside and any claims thatPioneer and Woodside might have against the Trust or the Partnership.

Based on the information available to the Trustee andits analysis outlined above, the Trustee believes that the benefits receivedunder the Conditional Settlement Agreement outweigh the potential benefits thatmay be achieved by the Trust litigating any of the asserted claims againstPioneer and Woodside, which would require the Trust to incur and assume therisk of further significant litigation costs. As a result, the Trustee believesthe Conditional Settlement Agreement is in the best interest of the unitholdersof the Trust. The Trustee has executed the Conditional Settlement Agreement andis recommending to the Court that the agreement be approved.

The Conditional Settlement Agreement is subject tocertain conditions, including approval by the Court. The Court has currentlyscheduled a hearing on the approval for May 21, 2007. MHLP and the Intervenorsare not signatories or parties to the settlement and they, or other unitholdersof the Trust, may 

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comment or object to thesettlement. The settlement is not final until approved by the Court. If theCourt approves the proposed settlement, it will enter an order that approvesthe settlement and dismisses the Lawsuit with prejudice as to all claims thatmay be brought on behalf of the Trust, either by the Trustee or by unitholdersseeking to assert claims on behalf of themselves or the Trust, against Pioneerand Woodside based on the facts asserted in the Lawsuit.

The Trustee will make thefull detail of the underlying data of the December 31, 2006 reserve reportavailable for use in connection with the sale of the Partnership’s RoyaltyProperties as part of the Trust termination. For more information regarding theestimated remaining life of each of the Royalty Properties, the estimatedfuture net revenues of the Royalty Properties and information relating tofarm-outs of interests on the Royalty Properties based on information providedby PNR to D&M, see pages 23 and 24 of this Form 10-K and Note 6 in theNotes to Financial Statements included elsewhere in this Form 10 K. The finaldistribution to unitholders will be an amount net of funds required to satisfyall Trust liabilities.

**TIMING OFLIQUIDATION**

The Trust Indenture provides that the Trust willterminate if the total amount of cash per year received by the Trust fallsbelow certain levels for each of three successive years. As a result ofcontinued declines in production on Royalty Properties nearing the end of theirestimated productive lives, Royalty income received by the Trust in 2002, 2003and 2004 fell below the Termination Threshold prescribed by the TrustIndenture. Under the proposed Conditional Settlement Agreement, Pioneer and theTrustee have agreed that Pioneer shall arrange for the sale of all assets ofthe Partnership as provided for under the Trust Indenture on, or as soon aspractical after, July 1, 2007, or on an earlier date as set forth in theproposed settlement. The Trustee filed a motion for approval of the ConditionalSettlement Agreement with the court on January 30, 2007. See “Business—LegalProceedings and Status of the Trust” in Item 1 of this Form 10-K.

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.

**Assets andLiabilities 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,  2006** | ** ** |
|------------------------------------------------------------|------------|-----------------------------|------------|
| ASSETS                                                     |       |                        |       |   |   |
| Cash and short  term investments                           |       |                        | $          | 797,074 |   |   |
| Interest  receivable                                       |       |                        | 2,970      |   |   |
| Net overriding  royalty interest in oil and gas properties |       |                        | 1,475,584  |   |   |
| Total assets                                               |       |                        | 2,275,628  |   |   |
| LIABILITIES                                                |       |                        |       |   |   |
| Reserve for Trust  expenses                                |       |                        | $          | 800,044 |   |   |
| Total liabilities                                          |       |                        | 800,044    |   |   |
| Net assets in process of  liquidation                      |       |                        | $1,475,584 |   |   |

 

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The net overriding royalty interest in oil and gasproperties at December 31, 2006 reflect the Trustee’s estimate of value(in the absence of third-party appraisals or evaluations), based on the Trust’sshare of future net revenues from the net overriding royalty interest in theproperties as of December 31, 2006. This estimate is based on the Trustee’scurrent assessment of the impact of selling existing assets based on currentmarket conditions, and includes the following assumptions:

·       TheTrust’s estimated share of oil and gas reserve volumes at December 31,2006, were derived from the reserve report prepared by DeGolyer and MacNaugton(D&M).

·       Forwardstrip commodity prices on December 31, 2006 and the escalated 2%thereafter.

·       Includesapproximately $1.4 million of future abandonment costs to be recouped by PNR.

·       Discountrate of 10%.

·       Futureincome taxes were not taken into account.

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.

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 23 and 24 of this Form 10-Kand Note 6 in the Notes to Financial Statements included elsewhere in this Form 10-K.Subject to the terms and approval of a final Conditional Settlement Agreement, thesale of the assets of the Trust estate may include the related rights toabandonment accruals made by PNR. As explained in “Regulation and Prices—PlatformAbandonment and Removal” on page 27 of this Form 10-K, PNR canwithhold from the Trust a reserve to cover its share of those futureabandonment and removal costs; however, no funds have been withheld as ofDecember 31, 2006.

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**DESCRIPTION OF ROYALTYPROPERTIES**

**Producing Acreage and Wells as of December 31,2006**

|                             | ** ** | ** **               | ** ** | ** ** | ** ** | **Producing Wells(1)** | ** ** |
|-----------------------------|------------|--------------------------|------------|------------|------------|-----------------------------|------------|
| ** **                  | ** ** | **Producing Acres** | ** ** | **Gross**  | ** ** | **Net**                     | ** ** |
| **Property**                | ** ** | ** **               | ** ** | **Gross**  | ** ** | **Net(2)**                  | ** ** | **Oil** | ** ** | **Gas** | ** ** | **Oil** | ** ** | **Gas** | ** ** |
| Offshore Louisiana(3)— |       |                     |       |       |       |                        |       |   |   |   |   |   |   |   |   |   |   |
| West Delta 61               |       | 5,000                    |       | 625        |       |                        | —     |   |   | 4 |   |   | — |   |   | .5 |   |
| Offshore  Texas(4)—    |       |                     |       |       |       |                        |       |   |   |   |   |   |   |   |   |   |   |
| Brazos A-7                  |       | —                   |       | —     |       |                        | —     |   |   | — |   |   | — |   |   | — |   |
| Brazos A-39                 |       | 5,760                    |       | 954        |       |                        | —     |   |   | 1 |   |   | — |   |   | .05 |   |
| Total                       |       | 10,760                   |       | 1,579      |       |                        | —     |   |   | 5 |   |   | — |   |   | .55 |   |
|                             |            |                          |            |            |            |                             |            |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)          Dual completions arecounted as one well. For information regarding wells producing at December 31,2006, see “Management’s Discussion and Analysis of Financial Condition andResults of Operations Status of the Trust—Properties Producing as of December31, 2006” in Item 7 on page 34 of this Form 10-K. As of January 31,2007, only the wells on Brazos A-39 and West Delta 61 were capable ofproducing.

(2)          Net Producing Acres arecalculated by multiplying gross producing acres by the net Royalty interest (asdefined by the Conveyance) attributable to the Trust for each property. Thecurrent net interests attributable to the Trust after giving effect to Farmoutagreements are described in Item 7 of this Form 10-K.

(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.

**Reserves**

A study of the proved oil and gas reservesattributable to the Partnership as of December 31, 2006, has been made byD&M. The following letter (the “Reserve Report”) summarizes such reservestudy. The Reserve Report reflects estimated reserve quantities and future netrevenue based upon estimates of the future timing of actual production withoutregard to when received in cash by the Trust, which differs from the manner inwhich the Trust recognizes and accounts for its Royalty income. For furtherinformation regarding the Net Overriding Royalty Interest, the Basis ofAccounting for the Trust and Supplemental Reserve Information, see Notes 2, 3and 6, respectively, in the Notes to Financial Statements contained in Item 8of this Form 10-K.

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

**APPRAISAL REPORTas ofDECEMBER 31, 2006onPROVED RESERVESofCERTAIN INTERESTSowned byMESA OFFSHORE TRUSTprepared forJPMORGAN CHASE BANK, N.A.**

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**TABLEof CONTENTS**
|                                 | ** ** | **Page** | ** ** |
|---------------------------------|------------|----------|------------|
| **FOREWORD**                    |       |     | 17         |   |   |
| Scope of Investigation          |       |     | 17         |   |   |
| Authority                       |       |     | 18         |   |   |
| Source of Information           |       |     | 18         |   |   |
| **CLASSIFICATION  of RESERVES** |       |     | 18         |   |   |
| **ESTIMATION  of RESERVES**     |       |     | 19         |   |   |
| **VALUATION  of RESERVES**      |       |     | 20         |   |   |
| **SUMMARY  and CONCLUSIONS**    |       |     | 21         |   |   |
| **APPENDIX**                    |       |     |       |   |   |

 

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

**APPRAISAL REPORTas ofDECEMBER 31, 2006onPROVED RESERVESofCERTAIN INTERESTSowned byMESA OFFSHORE TRUSTprepared forJPMORGAN CHASE BANK, N.A.**

**FOREWORD**

*Scope of Investigation*

This report presents an appraisal, as ofDecember 31, 2006, of the extent and value of the proved crude oil,condensate, and natural gas reserves of royalty interests in certain propertiesowned by the Mesa Offshore Trust (MOST) located offshore from Louisiana andTexas in the Gulf of Mexico. The Managing General Partner is Pioneer NaturalResources USA Inc. (PNR). This report was prepared at the request of JPMorganChase Bank, N.A., (the Trustee), 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, 2006.Net reserves are defined as that portion of the gross reserves attributable toMOST’s interests after deducting royalties and interests owned by others.

This report presents values that were estimated forproved reserves using initial prices provided by the Trustee and initial costsprovided by PNR. Future price and cost assumptions were provided by the Trustee.A detailed explanation of the price and cost assumptions used herein isincluded in the Valuation of Reserves section 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. Future income taxexpenses were not taken into account in the preparation of these estimates.Present worth is defined as future net revenue discounted at a specifiedarbitrary discount rate compounded monthly over the expected period ofrealization. In this report, present worth values using a nominal discount rateof 10 percent are reported in detail and values using nominal discount rates of5, 15, 20, and 25 percent are reported as totals in the appendix to thisreport.

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, The Bank of New York Trust Company,N.A., as attorney-in-fact for the Trustee.

*Source of Information*

Information used in the preparation of this report wasobtained from PNR’s files on behalf of the Trustee, from records on file withthe appropriate regulatory agencies, and from public sources. In thepreparation of this report we have relied, without independent verification,upon such information furnished by PNR and the Trustee with respect to propertyinterests, production from such properties, current costs of operation anddevelopment, current prices for production, the future plans for development ofthe properties, agreements relating to current and future operations and saleof production, 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 and are judged to be economically producible in future years fromknown reservoirs under existing economic and operating conditions and assumingcontinuation of current regulatory practices using conventional productionmethods and equipment. In the analyses of production-decline curves, reserveswere estimated only to the limit of economic rates of production under existingeconomic and operating conditions using prices and costs as of the date theestimate is made, including consideration of changes in existing pricesprovided only by contractual arrangements but not including escalations basedupon future conditions. The petroleum reserves are classified as follows:

*Proved—**Reserves*that havebeen proved to a high degree of certainty by analysis of the producing historyof a reservoir and/or by volumetric analysis of adequate geological andengineering data. Commercial productivity has been established by actualproduction, successful testing, or in certain cases by favorable core analysesand electrical-log interpretation when the producing characteristics ofthe 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—**Reserves* that arerecoverable from existing wells with current operating methods and expenses.

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 

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wells but are notrecoverable from existing wells. This classification of reserves requiresdrilling of additional wells, major deepening of existing wells, orinstallation of enhanced recovery or other facilities.

Reserves recoverable byenhanced recovery methods, such as injection of external fluids to provideenergy not inherent in the reservoirs, may be classified as proved developed orproved undeveloped reserves depending upon the extent to which such enhancedrecovery methods are in operation. These reserves are considered to be provedonly in cases where a successful fluid-injection program is in operation, apilot program indicates successful fluid injection, or information is availableconcerning the successful application of such methods in the same reservoir andit is reasonably certain that the program will be implemented.

**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.

Where appropriate the volumetric method was used toestimate the original oil in place (OOIP) and original gas in place (OGIP).Structure maps were prepared to delineate each reservoir, and isopach maps wereconstructed to estimate reservoir volume. Electrical logs, radioactivity logs,core analyses, and other available data were used to prepare these maps as wellas to estimate representative 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.

For depletion-type reservoirs or those whoseperformance disclosed a reliable decline in producing-rate trends or otherdiagnostic characteristics, reserves were estimated by the application ofappropriate decline curves or other performance relationships. In the analysesof production-decline curves, reserves were estimated only to the limits ofeconomic production based on current economic conditions.

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 throughDecember 31, 2006, were used to prepare the estimates shown herein. Grossproduction through December 31, 2006, was deducted from the gross ultimaterecovery to arrive at estimates of gross reserves. Production from the WestDelta Block 61 field was halted in the third quarter of 2005 as a result ofHurricane Katrina and production is expected to resume in August 2007. TheBrazos Block A-7 field ceased production in June 2006 and the leaseexpired during December 2006. According to PNR, there are no further plansfor this lease.

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,after reduction for fuel usage, flare, and shrinkage resulting from fieldseparation and processing. Condensate reserves estimated herein are those to beobtained by normal separator recovery.

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Estimatesof the gross and net proved reserves, as of December 31, 2006, of theproperties appraised are presented as follows. Oil and condensate reserves areexpressed in barrels (bbl) and gas reserves are expressed in thousands of cubicfeet (Mcf).

| ** **     | ** ** | **Oil and  Condensate  (bbl)** | ** ** | **Sales Gas  (Mcf)** | ** ** |
|----------------|------------|-------------------------------------|------------|---------------------------|------------|
| Gross Reserves |       |                                |       |                      |       |   |   |
| Proved         |       |                                | 140,323    |                      |       | 5,638,599 |   |
| Net Reserves   |       |                                |       |                      |       |   |   |
| Proved         |       |                                | 10,613     |                      |       | 360,062 |   |

 

**VALUATION of RESERVES**

This report has beenprepared using initial prices provided by the Trustee and initial costsprovided by PNR on behalf of the Trustee. 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 reserves were based on projections of estimated futureproduction and revenue prepared for these properties.

*Oil and CondensatePrices*

Initial oil and condensate prices furnished by theTrustee varied from $57.62 to $61.05 per barrel and were held constant for theproducing lives of the properties.

*Natural Gas Prices*

The natural gas prices furnished by the Trustee variedfrom $5.42 to $5.64 per thousand cubic feet of gas and were held constant forthe producing lives of the properties.

*Operating Expensesand Capital Costs*

The properties appraised are royalties. Therefore, nooperating expenses are incurred. The capital costs included at the request of theTrustee are plugging, abandonment, and decommissioning costs related tofacilities of prior producing properties.

Theestimated future revenue to be derived from the production and sale of MOST’snet proved reserves, as of December 31, 2006, under the economicassumptions furnished by the Trustee is summarized as follows, expressed indollars ($):

| ** **                    | ** ** | **Proved  ($)** | ** ** |
|-------------------------------|------------|-----------------|------------|
| Future Gross  Revenue         |       | 2,588,452       |       |
| Operating  Expenses           |       | 0               |       |
| Capital Costs                 |       | 1,411,141       |       |
| Future Net  Revenue*          |       | 1,177,311       |       |
| Present Worth at 10  Percent* |       | 767,893         |       |

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*       Futureincome tax expenses were not taken into account in the preparation of theseestimates.

The appendix bound with this report presentstabulations and projections of revenue from the proved reserves for theinterests appraised.

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 

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and 30(a)—(b) ofStatement of Financial Accounting Standards No. 69 (November 1982) ofthe FASB and Rules 4—10(a) (1)—(13) of Regulation S—X andRule 302(b) of Regulation S—K of the SEC; provided, however, that(i) certain estimated data have not been provided with respect to changesin reserves information and (ii) future income tax expenses have not beentaken into account in estimated the future net revenue and present worth valuesset forth herein.

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 therefor.

**SUMMARY and CONCLUSIONS**

Evaluatedherein are royalty interests in certain properties owned by MOST locatedoffshore from Louisiana and Texas in the Gulf of Mexico. Estimates of MOST’snet proved reserves, as of December 31, 2006, of the properties appraisedare presented as follows. Oil and condensate reserves are expressed in barrels(bbl) and gas reserves are expressed in thousands of cubic feet (Mcf).

| ** **                   | ** ** | **Proved** | ** ** |
|------------------------------|------------|------------|------------|
| Net Oil and  Condensate, bbl |       | 10,613     |       |
| Net Sales Gas, Mcf           |       | 360,062    |       |

 

Estimatedrevenue and costs attributable to MOST’s interests in the proved reserves, asof December 31, 2006, of the properties evaluated under the aforementionedassumptions concerning future prices and costs are summarized as follows,expressed in dollars ($):

| ** **                    | ** ** | **Proved  ($)** | ** ** |
|-------------------------------|------------|-----------------|------------|
| Future Gross  Revenue         |       | 2,588,452       |       |
| Operating  Expenses           |       | 0               |       |
| Capital Costs                 |       | 1,411,141       |       |
| Future Net  Revenue*          |       | 1,177,311       |       |
| Present Worth at 10  Percent* |       | 767,893         |       |

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*       Futureincome tax expenses were not taken into account in the preparation of theseestimates.

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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: April 10, 2007 |                     |
|                             |                          |
|                        | Paul J. Szatkowski, P.E. |
|                        | Senor Vice President     |
|                        | DeGolyer and MacNaughton |

 

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There are numerous uncertainties inherent inestimating quantities of proved reserves and in projecting the future rates ofproduction and timing of development expenditures, including many factorsbeyond the control of the producer. The preceding reserve data in the ReserveReport represent estimates only and should not be construed as being exact.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 tothe Partnership will be affected by future changes in various economic factorsutilized in estimating future gross and net revenues from the RoyaltyProperties. Therefore, the estimates of reserves set forth in the ReserveReport are to a large extent hypothetical and differ in significant respectsfrom estimates of reserves attributable to a working interest.

Moreover, the discounted present values in the ReserveReport should not be construed as the current market value of the estimated gasand oil reserves attributable to the Royalty Properties or the costs that wouldbe incurred to obtain equivalent reserves, since a market value determinationwould include many additional factors. In accordance with applicableregulations of the SEC, estimated future net revenues were based, generally, oncurrent prices and costs, whereas actual future prices and costs may bematerially greater or less. The estimates in the Reserve Report use marketprices as of December 31, 2006. These prices (having weighted average yearend prices of $57.62 to $61.05 per barrel of oil and condensate and $5.42 to $5.64per Mcf of natural gas as of December 31, 2006) were held constant overthe estimated life of the Royalty Properties. These prices were influenced byseasonal demand for natural gas and may not be the most appropriate orrepresentative prices to use for estimating future revenues or related reservedata. The average price of natural gas sold from the Royalty Properties during2006 was $7.65 per Mcf, representing a combination of contract prices and spotmarket prices, while the average price of crude oil, condensate and natural gasliquids was $58.64 per barrel.

The following is a summary of the estimated remaininglife for each of the Royalty Properties provided to the Trustee by D&M asof December 31, 2006. There are numerous uncertainties present inestimating the remaining productive lives for the Royalty Properties. Thefollowing summary represents an estimate only and should not be construed asbeing exact. The estimated remaining productive life of each 

property variesdepending on the recoverable reserves and annual production assumed by D&M.In addition, future economic and operating conditions may cause significantchanges in these estimates.

| **Property**  | ** ** | ** ** | ** ** | **Productive Life(1)(2)** | ** ** |
|---------------|------------|------------|------------|--------------------------------|------------|
| West Delta 61 |       |       | 8 years    |                           |       |
| Brazos A-39   |       |       | 5 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 to terminateeven though some of the Royalty Properties continued to have remainingproductive lives. See “Business—Legal Proceedings and Status of the Trust” on page 8of this Form 10-K and see “Business—Timing of Liquidation” on page 12of this Form 10-K.

(2)          Estimates of remaininglives may vary significantly from year to year.

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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 $1,200,000 annually.

The general and administrative costs and expenses ofthe Trust may increase in future years, depending on the amount of royaltyincome, increases in accounting, engineering, legal and other professional feesand other factors.

**CONTRACTS**

**General**

PNR has advised the Trustthat during 2006 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 in2006 were generally higher than spot market prices in 2005.

**Market for NaturalGas**

The amount of cash distributions by the Trust isdependent on, among other things, the sales prices for natural gas producedfrom the Royalty Properties and the quantities of gas sold. The natural gasindustry in the United States during the 1990’s was affected generally by asurplus in natural gas deliverability in comparison to demand. Demand for gasdeclined during this period due to a number of factors including theimplementation of energy conservation programs, a shift in economic activityaway from energy intensive industries and competition from alternative fuelsources such as residual fuel oil, coal and nuclear energy. In late 2001 andearly 2002, demand for natural gas increased as a result of the increase inclean burning natural gas fired power generation, the increase in the usage ofelectrical power fueled by the expanding U.S. economy and a return toseasonally cold winters. Annual wellhead prices generally increased from $2.95per Mcf in 2002, increased to $5.09 per Mcf in 2003, to $5.49 per Mcf in 2004,to $5.65 in 2005 and increased to $6.42 in 2006 according to the Natural GasMonthly published by the Energy Information Administration of the Department ofEnergy.

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

**Competition**

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

**Marketing ofLiquids**

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.

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**REGULATION ANDPRICES**

**General**

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

**Operating Hazardsand Uninsured Risks**

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

**FERC Regulation**

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

**State and OtherRegulation**

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

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 

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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 offshore facilitieslocated on the OCS. This amount is subject to upward regulatory adjustment upto $150 million. Responsible parties for more than one offshore facilityare required to provide OSFR only for their offshore facility requiring thehighest OSFR. In 1998, the Minerals Management Service (“MMS”) adoptedregulations for establishing the amount of OSFR required for particularfacilities. The amount of OSFR increases as the volume of a facility’sworst-case oil spill increases. Accordingly, for facilities with worst-casespills of less than 35,000 barrels, only $35 million in OSFR is required;for worst-case spills of over 35,000 barrels, $70 million is required; forworst-case spills of over 70,000 barrels, $105 million is required; andfor worst-case spills of over 105,000 barrels, $150 million is required.In addition, all OSFR below $150 million remains subject to upwardregulatory adjustment if warranted by the particular operational,environmental, human health or other risks involved with a facility. Under thisregulation, PNR is required to maintain $35 million in OSFR for itsoffshore facilities. PNR is maintaining its OSFR in this amount by insurance.Although the working interest owners have advised the Trust that currentenvironmental regulation has had no material adverse effect on the workinginterest owners’ present method of operations, the impact of the recentlyadopted regulatory changes, and of future environmental regulatory developmentssuch as stricter environmental regulation and enforcement policies, cannotpresently be quantified.

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

**PlatformAbandonment and Removal**

PNR is responsible for theabandonment and removal of its offshore drilling and production structureswithin one year after the cessation of production, although extensions can berequested. PNR can withhold from the Trust a reserve to cover its share ofthose future abandonment and removal costs; however, no funds have beenwithheld as of December 31, 2006. See Item 7 of this Form 10-K andNote 3 in the Notes to Financial Statements for amounts withheld as of December 31,2006 and 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 oil prices fluctuate due to a numberof factors, and lower prices will reduce net proceeds available to the Trustand distributions to Trust unitholders.**

The Trust’s quarterly distributions are highlydependent upon the prices realized from the sale of natural gas and oil, and amaterial decrease in these prices could reduce the amount of Trustdistributions. Natural gas and oil prices can fluctuate widely on amonth-to-month basis in response to a variety of factors that are beyond thecontrol of the Trust and the working interest owners. Factors that contributeto price fluctuation include, among others: political disruption, war, or otherarmed conflict in oil producing regions, in particular the war in Iraq;worldwide economic conditions; weather conditions; the supply and price offoreign natural gas and oil; the level of consumer demand; the price and availabilityof alternative fuels; the proximity to, and capacity of, transportationfacilities; and the effect 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.

When natural gas and oil prices decline, the Trust isaffected in two ways. First, net royalties are reduced. Second, exploration anddevelopment activity on the underlying properties may decline as some projectsmay become uneconomic and are either delayed or not undertaken. The volatilityof energy prices reduces the predictability of future cash distributions tounitholders. Substantially all of the natural gas and natural gas liquidsproduced from the Royalty Properties is being sold on the spot market or undershort-term contracts.

**Increased production and development costs for theRoyalty will result in decreased Trust distributions.**

Production and development costs attributable to theRoyalty are deducted in the calculation of the Trust’s share of net proceeds. Productionand development costs are impacted by increases in commodity prices bothdirectly, through commodity price-dependent costs such as electricity, andindirectly, as a result of demand-driven increases in costs of oilfield goodsand services. Accordingly, higher or lower production and development costs,without concurrent increases in revenues, directly decrease or increase theamount received by the Trust for the Royalty.

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

**Trust reserve estimates depend on many assumptionsthat may prove to be inaccurate, which could cause both estimates of reservesand estimated future revenues to be too high 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;

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

·       theavailability of enhanced recovery techniques; and

·       relationshipswith landowners, working interest partners, pipeline companies and others.

Changes in these factors and assumptions canmaterially change reserve estimates and future net revenue 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. Ultimately, actual production, revenues and expendituresfor the underlying properties and therefore actual net proceeds payable to theTrust, will vary from estimates and those variations could be material. Resultsof drilling, testing and production after the date of those estimates mayrequire substantial downward revisions or write-downs of reserves.

The Trustee also relies entirely on reserve estimatesand related information prepared by PNR and the independent reserve engineerengaged by the Trust. While the Trustee has no reason to believe the reserveestimates and related estimates of value included in this report are notaccurate, to the extent additional information exists that could affect theirreserve estimates, the estimated reserves in these reports and relatedestimates of value could also be too low.

**Estimates and accruals of costs by PNR may be greateror lesser than future estimated or actual costs.**

As discussed in Item 7 and Note 3 to theNotes to Financial Statements, at December 31, 2006 PNR estimated theTrusts portion of incurred and future abandonment costs to be approximately$1.4 million. Future distributions to the Trust will be reduced until such timethat these costs are recouped by PNR. As of December 31, 2006,approximately $867,000 of the estimated $1.4 million has been spent by PNR.

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**Operating risks for the working interest owners’interests in the Royalty Properties can adversely affect Trust distributions.**

There are operational risks and hazards associatedwith the production and transportation of natural gas, including withoutlimitation natural disasters, blowouts, explosions, fires, leakage of naturalgas, releases of other hazardous materials, mechanical failures, cratering andpollution. Any of these or similar occurrences could result in the interruptionor cessation of operations, personal injury or loss of life, property damage,damage to productive formations or equipment, damage to the environment ofnatural resources, or cleanup obligations. The occurrence of drilling,production or transportation accidents at any of the Royalty Properties willreduce Trust distributions by the amount of uninsured costs. These occurrencesinclude blowouts, cratering, explosions and other environmental damage.Offshore activities are also subject to a variety of operating risks such ashurricanes and other weather disturbances. These accidents and other naturaldisasters may result in personal injuries, property damage, damage toproductive formations or equipment and environmental damages. Any uninsuredcosts would be deducted as a production cost in calculating net proceedspayable to the Trust.

**Terrorismand continued hostilities in the Middle East could decrease Trust distributionsor the market price of the units of beneficial interest of the Trust.**

Terrorist attacks and the threat of terrorist attacks,whether domestic or foreign, as well as military or other actions taken inresponse, cause instability in the global financial and energy markets.Terrorism, the war in Iraq and other sustained military campaigns couldadversely affect Trust distributions or the market price of the Units inunpredictable ways, including through the disruption of fuel supplies andmarkets, increased volatility in natural gas prices, or the possibility thatthe infrastructure on which the operators developing the underlying propertiesrely could be a direct target or an indirect casualty of an act of terror.

**The operators of the working interests are subject toextensive 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.

**The unitholders and the Trustee have no control overthe operation or development of the Royalty Properties and have littleinfluence 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 relies upon the working interest ownersand managing general partner for information regarding 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 regulatory changesand the number of producing wells and acreage, (ii) plans for futureoperating and capital expenditures, (iii) geological data relating toreserves, 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 

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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.

**The owner of any Royalty Property may abandon anyproperty, 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 (through thePartnership) the Royalty on the transferred portion of the Royalty Properties,and the current owner of the Royalty Properties would have no continuingobligation to the Trust for those properties.

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 “Business—Timing ofLiquidation” in Item 1 of this Form 10-K.

**The Royalty will be sold and the Trust is beingterminated.**

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 “Business—Timing of Liquidation.”

**Trust assets are depleting assets and, if the workinginterest owners or other operators of the Royalty Properties do not performadditional development projects, the assets may 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.

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Because the net proceeds payable to the Trust arederived from the sale of depleting assets, the portion of distributions tounitholders attributable to depletion may be considered a return of capital asopposed to a return on investment. Distributions that are a return of capitalwill ultimately diminish the depletion tax benefits available to the Trustunitholders, which could reduce the market value of the Trust units over time.Eventually, properties underlying the Trust’s Royalty will cease to produce incommercial quantities and the Trust will, therefore, cease to receive anydistributions of net proceeds therefrom.

**Unitholders have limited 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 have limited ability to enforce theTrust’s rights against the current or future owners of the Royalty Properties.**

The Trust Agreement and related trust law permit theTrustees and the Trust to sue the working interest owner to compel it tofulfill the terms of the Conveyance of the Royalty. If the Trustee does nottake appropriate action to enforce provisions of the Conveyance, the recourseof a unitholder would likely be limited to bringing a lawsuit against theTrustee to compel the Trustee to take specified actions. Unitholders probablywould not be able to sue the working interest owner directly.

**Thelimited liability of the Trust unitholders is uncertain.**

The Trust unitholders arenot protected from the liabilities of the Trust to the same extent that ashareholder would be protected from a corporation’s liabilities. The structureof the Trust does not include the interposition of a limited liability entitysuch as a corporation or a limited partnership which would provide furtherlimited liability protection to Trust unitholders. While the Trustee is liablefor any excess liabilities incurred if the Trustee fails to insure that suchliabilities are to be satisfied only out of Trust assets, under the laws ofTexas, which are unsettled on this point, a holder of units may be jointly andseverally liable for any liability of the Trust if the satisfaction of suchliability was not contractually limited to the assets of the Trust and theassets of the Trust and the Trustee are not adequate to satisfy such liability.As a result, Trust unitholders may be exposed to personal liability.

**Item 1B.**               UnresolvedStaff Comments.

There were no unresolvedSecurities and Exchange Commission comments as of December 31, 2006.

**Item 2.**                        Properties.

Reference is made to “Business—Descriptionof Royalty Properties” contained in Item 1 of this Form 10-K.

**Item 3.**                        LegalProceedings.

**Referenceis made to “Business—Legal Proceedings and Status of the Trust” contained inItem 1 of this Form 10-K.**

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

There were no matters submitted to a vote ofunitholders during the fourth quarter of 2006.

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**PART II**

**Item 5.**                        Market forthe Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchasesof Equity Securities.

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.OB. In 2006, theTrust had gross Royalty income of $145,642. However, no Royalty income will bedistributed to the unitholders until the Trustee recoups Trust expenses being paidfrom 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, 2006 were as follows:

| ** **     | ** ** | **2006** | ** ** | **2005** | ** ** |
|----------------|------------|----------|------------|----------|------------|
| ** **     | ** ** | **High** | ** ** | **Low**  | ** ** | **Distribution  Paid** | ** ** | **High** | ** ** | **Low** | ** ** | **Distribution  Paid** | ** ** |
| First Quarter  |       | $        | 0.23       |     | $          | 0.10 |   |   | $ | — |   |   | $ | 0.04 |   | $ | 0.02 |   |   | $ | — |   |   |
| Second Quarter |       | $        | 0.18       |     | $          | 0.09 |   |   | $ | — |   |   | $ | 0.04 |   | $ | 0.02 |   |   | $ | — |   |   |
| Third Quarter  |       | $        | 0.16       |     | $          | 0.09 |   |   | $ | — |   |   | $ | 0.07 |   | $ | 0.03 |   |   | $ | — |   |   |
| Fourth Quarter |       | $        | 0.10       |     | $          | 0.05 |   |   | $ | — |   |   | $ | 0.12 |   | $ | 0.04 |   |   | $ | — |   |   |

 

At March 30, 2007, the 71,980,216 unitsoutstanding were held by 11,552 unitholders of record.

**Item6.**                        SelectedFinancial Data.

| ** **                           | ** ** | **2006** | ** ** | **2005** | ** ** | **2004**  | ** ** | **2003** | ** ** | **2002** | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|-----------|------------|----------|------------|----------|------------|
| Royalty income                       |       | $        | 145,642    |     | $          | 2,284,914 |       | $        | —     |     | $          | — |   | $ | — |   |
| Distributable  income                |       | $        | —     |     | $          | —    |       | $        | —     |     | $          | — |   | $ | — |   |
| Distributable  income per unit       |       | $        | —     |     | $          | —    |       | $        | —     |     | $          | — |   | $ | — |   |
| Accumulated  deficit at year  end(i) |       | $        | (1,417,808 | )        | $          | —    |       | $        | (59,035    | )        | $          | (696,712 | ) | $ | (825,616 | ) |
| Total assets at year  end.           |       | $        | 802,981    |     | $          | 1,851,428 |       | $        | 387,986    |     | $          | 951,557 |   | $ | 1,497,883 |   |

 

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(i)             Accumulated deficitat year end represents amounts that will be deducted from future gross proceedson the Royalty Properties, which will reduce future Royalty income. No Royaltyincome will be distributed to unitholders in the future until PNR recoups theaccumulated deficit.

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**Item 7.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations.

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

**Critical AccountingPolicies**

The financial statements of the Trust are prepared onthe following basis:

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

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

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

This basis for 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**

Hurricane Katrina**struckthe Gulf of Mexico in August 2005. PNR has notified the Trust of itscurrent assessments regarding damages from Hurricanes Katrina and Rita toproduction facilities for properties in which the Trust has an interest. Theoperator of the West Delta properties has informed PNR that the West Deltaproperties have been shut in since August 27, 2005 due to damage to theplatform, the pipeline and the sales terminal. The operator has notified PNRthat they expect production at West Delta to resume during the second quarterof 2007.

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**. The Trustee has takensteps to begin the process of liquidating the Trust. See “Business—Timing ofLiquidation” below in Item 1 of this Form 10-K. The Trustee, which has noauthority or discretionary control over the timing of expenditures, productionor income on the Royalty Properties, has no discretion regarding the occurrenceof the Termination Threshold or its consequences.

The Trust Indentureprovides the Trustee a two-year period during which it must sell all of theTrust properties. The Trust Indenture provides that such properties must besold for cash and not for any other consideration. The Trustee expects that thesale process will be open to any persons desiring to participate, but, as iscustomary, access to information and participation may be limited to personswho execute confidentiality agreements regarding information provided by theworking interest owners. The Trustee may also require bidders to identifythemselves clearly and to represent or evidence sufficient financing in orderto participate, as the Trustee expects payment will be required promptly afterthe close of bidding 

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withoutany financing conditions. Accordingly, the auction may not be a “public”auction in the sense that it may not be open to anyone who does not satisfythese requirements. The Trustee is currently reviewing a potential onlinebidding process for participants in order to provide current public informationon bidding to the marketplace. The Trustee will also determine a duration ofbidding that it deems in the best interest of the Unitholders.

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

*Properties producing as of December 31, 2006*

| **Property**            | ** ** | ** ** | ** ** | **Number of  Producing  wells(1)** | ** ** | **Estimated  Productive  Life(1)** | ** ** | **Estimated  Future  Royalty  Income(2)** | ** ** |
|-------------------------|------------|------------|------------|-----------------------------------------|------------|------------------------------------|------------|-------------------------------------------|------------|
| West Delta  No. 61 |       |       | 4          |                                    |       |                               | 8 years    |                                      |       | $ | 1,527,494 |   |
| Brazos A-39             |       |       | 1          |                                    |       |                               | 5 years    |                                      |       | $ | 528,712 |   |

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(1)          Information obtainedfrom December 31, 2006 reserve report prepared by D&M.

(2)          Representsestimated future royalty income from the December 31, 2006 reserve report.Future royalty income was calculated using oil and gas spot prices in effect atDecember 31, 2006 of $57.62 to $61.05 per barrel and $5.42 to $5.64 perthousand cubic feet.

*Properties abandoned or scheduled for abandonment asof December 31, 2006*

| **Property**            | ** ** | ** **                                                                      | ** ** | **Status** | ** ** |
|-------------------------|------------|---------------------------------------------------------------------------------|------------|------------|------------|
| Brazos A-7              |       | Abandoned  in 2005 (Newfield platform to be abandoned in 2007)                  |       |
| 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 andOperational Review**

As discussed inItem 1 of this Form 10-K, PNR has advised the Trust that during2006, its offshore gas production was marketed under short-term contracts atspot market prices primarily to TOTAL S.A. and that it expects to continue tomarket its production under short-term contracts for the foreseeable future.Spot market prices for natural gas were on the average higher in 2006 than spotmarket prices in 2005.

The amount of cashdistributed by the Trust is dependent on, among other things, the sales prices andquantities of gas, crude oil, condensate and natural gas liquids produced fromthe Royalty Properties and the quantities sold. Substantial uncertainties existwith regard to future gas and oil prices, which are subject to fluctuations dueto the regional supply and demand for natural gas and oil, production levelsand other activities of the Organization of the Petroleum Exporting Countries (“OPEC”)and other oil and gas producers, weather, storage levels, industrial growth,conservation measures, competition and other variables.

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Belowis a summary of Royalty income received on the Trust properties for each of theyears ended December 31, 2006, 2005 and 2004:

| ** **                            | ** ** | **2006**   | ** ** | **2005**  | ** ** | **2004**  | ** ** |
|---------------------------------------|------------|------------|------------|-----------|------------|-----------|------------|
| Gross proceeds @  90%                 |       | $          | 239,356    |      | $          | 2,085,418 |       | $ | 810,336 |   |
| Operating  expenditures @ 90%         |       | (103,474   | )          | (104,265  | )          | (172,594  | )          |
| Change in  abandonment estimate @ 90% |       | (1,400,141 | )          | —    |       | —    |       |
| Capital  expenditures @ 90%(1)        |       | (8,034     | )          | 375,338   |       | —    |       |
| Net proceeds  (deficit)               |       | (1,272,293 | )          | 2,356,491 |       | 637,742   |       |
| Increase  (decrease) in deficit       |       | 1,417,950  |       | (71,349   | )          | (637,742  | )          |
| Net proceeds  after deficit recovery  |       | 145,657    |       | 2,285,142 |       | —    |       |
| Royalty income (99.99%)               |       | $          | 145,642    |      | $          | 2,284,914 |       | $ | — |   |

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(1)          In 2005, the Trust (throughthe Partnership) received gross proceeds of $375,338 from PNR related to thesale of the South Marsh Island 155 platform that was abandoned by PNR and forcasings related to the PNR platform at Brazos A-39.

Belowis a summary of distributable income for the years ended December 31,2006, 2005 and 2004:

| ** **                              | ** ** | **Years Ended December 31,** | ** ** |
|-----------------------------------------|------------|---------------------------------------------|------------|
| ** **                              | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| Royalty income                          |       | $                                           | 145,642    |   | $ | 2,284,914 |   | $ | — |   |
| Interest income                         |       | 29,293                                      |       | 8,512 |   | 4,493 |   |
| General and  administrative expenses    |       | (174,935                                    | )          | (2,293,426 | ) | (4,493 | ) |
| Distributable  income                   |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Distributable  income per unit          |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Accumulated deficit (as  of period end) |       | $                                           | (1,417,808 | ) | $ | — |   | $ | (59,035 | ) |

 

***Below is a summary of general and administrative expensesand the adjustments made to the reserve for trust expenses:***

| ** **                                                 | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                 | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| General and  administrative costs incurred during the year |       | $                                           | 1,223,271  |   | $ | 824,691 |   | $ | 567,461 |   |
| (Deductions from)  additions to reserve for Trust Expenses |       | (1,048,336                                  | )          | 1,456,428 |   | (562,968 | ) |
| General and  administrative costs as reported              |       | $                                           | 174,935    |   | $ | 2,281,119 |   | $ | 4,493 |   |

 

General and administrativeexpenses of the Trust for 2006 increased 48% to $1,223,271 for 2006 as comparedto $824,691 for 2005. The increase in general and administrative expenses in2006 is primarily due to an increase in legal fees as a result of pending litigationand the anticipated sale of Trust properties pursuant to the Trust’stermination. In addition, the Trust incurred additional expenditures in 2005for the independent reserve studies performed as of March 31, 2005 and December 31,2005 and for the independent joint venture auditor to perform a review ofcertain historical expenditures and revenue receipts on Trust properties.

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Below is an operationalreview of the remaining producing Trust properties:

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

| ** **                            | ** ** | **2006**   | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------|------------|------------|------------|----------|------------|----------|------------|
| Gross proceeds @  90%                 |       | $          | 152,215    |     | $          | 156,378  |       | $ | 160,014 |   |
| Operating  expenditures @ 90%         |       | (87,211    | )          | (83,470  | )          | (171,043 | )          |
| Change in  abandonment estimate @ 90% |       | (1,269,806 | )          | —   |       | —   |       |
| Capital  expenditures @ 90%           |       | —     |       | 6,750    |       | —   |       |
| Net proceeds (deficit)                |       | $          | (1,204,802 | )        | $          | 79,658   |       | $ | (11,029 | ) |

 

The Brazos A-7 and A-39 blocks continuedto experience a decrease in natural gas production due to natural productiondecline. As of December 31, 2006, these two blocks had one well capable ofproducing, the Brazos A-39 # 5. The Brazos A-7 No. B-1well, operated by Newfield, is no longer producing as of December 31,2006. PNR entered into farmout agreements for the Partnership’s interest inboth of these blocks so that two exploration prospects could be drilled and inwhich the Trust will retain an overriding royalty interest. The first prospecton Brazos A-7 was drilled during 2003 and was determined to be a dryhole. As such, the well was plugged and abandoned. In 2005, PNR performedabandonment procedures at the PNR operated Brazos A-7 and the A-39blocks, with minor sitework clearance remaining. In 2005, the Trust received a$6,750 credit for casings related to the PNR platform at Brazos A-39. Theseabandonment procedures were substantially completed during 2006.

The second exploration prospect, the Brazos A-39#5, was drilled on Brazos A-39, which PNR announced as a discovery. Aproduction test was completed in 2005. PNR, the operator on this property, hasinformed the Trustee that the lower horizon of the prospect was determined tobe non-commercial, while the middle horizon in the Big Hum 4 sand produced at10,000 Mcf of gas per day during a seventeen hour flow test. This wellcame on line April 20, 2006. However, this well has been shut in from timeto time since then as the operator has encountered and addressed hydrogensulfide issues. The well has also produced a carbon dioxide content thatexceeds pipeline specifications. This higher content requires the operator tomix production at the platform with production from other fields in order totransport the product. Production is being routed to the A-52C platformowned by Coldren Resources LP. That platform is being operated by Arena, whichis also serving as the contract operator for the Midway property. The well wasshut in July 21, 2006 by Williams Pipeline due to reported detection ofmercury in the gas stream. Following the installation of vessels with mercuryabsorbing media and negotiation of the required agreements with the owner andoperator of the Brazos A-52C host platform, the well was returned to productionon February 13, 2007. The current production rate is 2.5 – 3.2 MMCFD with 5,000psi flowing tubing pressure. The following tubing pressure continues togradually decline.

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 Partnership’s net profits interest, butexpressly providing that the farmed out interest would not be subject to the Partnership’snet profits 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 Partnership’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 Partnership’s net profits interest.

PNR continues to own the undivided one-half interestnot burdened by the Partnership’s net profits interest and will participate inand operate the well as owner of that undivided one-half interest (subject to 

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an agreement with Woodsideto grant Woodside such interest in PNR’s remaining undivided one-half interestto equalize those parties participation in the well).

PNR has noted to theTrustee that the Farmout Agreement enabled the drilling costs of theseprospects to be carried on the Partnership’s interest in part by Woodside. PNRfurther noted that the Partnership’s net profits interest would not haveentitled the Trust (through the Partnership) to payment until drilling costsand applicable interest were recovered, whereas the overriding royalty interestretained under the Farmout Agreement entitles the Trust (through thePartnership) to payments prior to the recoupment of expenses incurred byWoodside and PNR. As noted above, the first prospect on Brazos A-7 wasdetermined to be a dry hole. Under the Farmout Agreement and relatedagreements, those drilling and abandonment costs have been born entirely by PNRand Woodside and are not subject to recoupment from any proceeds otherwisepayable to the Partnership or the Trust. Similarly, the Partnership’s currentinterest in the “Midway” prospect on Brazos A-39 will be entitled topayment prior to PNR’s and Woodside’s recovery of expenses for drilling,completion, sub-sea tie backs and other costs.

***West Delta 61 and Other***

| ** **                               | ** ** | **2006** | ** ** | **2005** | ** ** | **2004**  | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|-----------|------------|
| Gross proceeds @  90%                    |       | $        | 87,141     |     | $          | 1,929,040 |       | $ | 650,322 |   |
| Operating  expenditures @ 90%            |       | (16,265  | )          | (20,795  | )          | (1,551    | )          |
| Change in  abandonment expenditures @90% |       | (130,333 | )          | —   |       | —    |       |
| Capital  expenditures @ 90%              |       | (8,034   | )          | —   |       | —    |       |
| Net proceeds (deficit)                   |       | $        | (67,491    | )        | $          | 1,908,245 |       | $ | 648,771 |   |

 

Hurricane Katrina**struckthe Gulf of Mexico in August 2005. The operator of the West Deltaproperties informed PNR that the West Delta properties have been shut in since August 27,2005 due to damage to the platform, the pipeline and the sales terminal. Theoperator has notified PNR that they expect production at West Delta to resume duringthe second quarter of 2007. The proceeds for the year ended December 31,2006 consist of revenue adjustments related to prior periods received by theTrust during 2006.

ThePNR-operated wells ceased production in 2002, and the wells were plugged andabandoned by year-end with the facilities being completely abandoned during2003. The only remaining wells on this block are in West Delta 61. PNR farmedout a portion of West Delta 61 to Stone Energy retaining a 12.5% (11.25% net tothe Trust through the Partnership) overriding royalty 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 Partnership’s interest in the blocks it believes may be producedeconomically, retaining an overriding royalty interest for the Partnership.

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***AbandonmentExpenditures***

Thebelow table provides a rollforward of the abandonment and removal costs cashreserve that PNR has withheld from the Partnership and 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   |   |
| Abandonment cost  incurred (Brazos A-7#4,A-39A1A,A-2 and A-3A Matagorda  Island 624, South Marsh Island 155) |   | (348,066   | )         |
| Balance, December 31, 2006                                                                              |   | $          | —    |   |

 

During the first ninemonths of 2006, PNR exhausted the $348,066 cash reserve established as ofDecember 31, 2005. In the third quarter of 2006, PNR revised their estimate ofabandonment expenses incurred, but not recouped from the Partnership andexpenses yet to be incurred for properties, in which the Partnership has aninterest to approximately $1.4 million. This revision was caused by increasedwork; necessary because of damages caused by Hurricane Katrina, and increasedday rates for labor due to the high demand for labor following HurricanesKatrina and Rita. As of December 31, 2006, PNR has spent approximately $867,000of the $1.4 million estimate, while approximately $533,000 of PNR’s originalestimate for total repairs remains to be spent. As the reserve for futureabandonment cost was fully utilized during the year, the total $1.4 million ofthe Partnership’s interest in estimated repairs will be deducted from anyfuture gross proceeds on the Royalty Properties, which will reduce futureRoyalty income. No Royalty income will be distributed to unitholders in thefuture until PNR recoups the Partnership’s portion of abandonment expenses fromgross proceeds.

***Liquidity andCapital Resources***

In accordance with theprovisions of the Trust conveyance, generally all revenues received by theTrust, net of Trust administrative expenses and any cash reserves establishedfor the payment of contingent or future obligations of the Trust, aredistributed currently to the unitholders.

The Trust’s source of cashis the Royalty income received from the Partnership’s share of the net proceedsfrom the Royalty Properties. Reference is made to Note 6 in the Notes toFinancial Statements under Item 8 of this Form 10-K for estimates offuture Royalty income attributable to the Partnership, of which the Trust has a99.99% interest.

***Production andPrice Review***

Production volumes fornatural gas decreased to 28,517 Mcf in 2006 as compared with 209,697 Mcf in2005. The average sales price received for natural gas in 2006 was $7.65 perMcf as compared with $7.01 per Mcf in 2005. Crude oil, condensate and naturalgas liquids production volumes decreased to 359 barrels in 2006 as compared to12,313 barrels in 2005. The average sales price in 2006 for crude oil,condensate and natural gas liquids was $58.64 per barrel as compared with$48.97 per barrel in 2005.

Production volumes fornatural gas increased to 209,697 Mcf in 2005 as compared with 92,254 Mcf in2004. The average sales price received for natural gas in 2005 was $7.01 perMcf as compared with $5.38 per Mcf in 2004. Crude oil, condensate and naturalgas liquids production volumes increased to 12,313 barrels in 2005 as comparedto 9,632 barrels in 2004. The average sales price in 2005 for crude oil,condensate and natural gas liquids was $48.97 per barrel as compared with$32.57 per barrel in 2004.

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***Off-Balance Sheet Arrangements***

***None.***

**Item 7A. Quantitativeand Qualitative Disclosures About Market Risk.**

Not applicable.

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

**MESAOFFSHORE TRUSTSTATEMENTS OF DISTRIBUTABLE INCOME**

| ** **                           | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------|------------|---------------------------------------------|------------|
| ** **                           | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| Royalty income                       |       | $                                           | 145,642    |   | $ | 2,284,914 |   | $ | — |   |
| Interest income                      |       | 29,293                                      |       | 8,512 |   | 4,493 |   |
| General and  administrative expenses |       | (174,935                                    | )          | (2,293,426 | ) | (4,493 | ) |
| Distributable income                 |       | $                                           | —     |   | $ | — |   | $ | — |   |
| Distributable income per  unit       |       | $                                           | —     |   | $ | — |   | $ | — |   |

 

**STATEMENTSOF ASSETS, LIABILITIES AND TRUST CORPUS**

| ** **                                                                         | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                         | ** ** | **2006**              | ** ** | **2005** | ** ** |
| ASSETS                                                                             |       |                  |       |   |   |
| Cash and short-term  investments                                                   |       | $                     | 797,074    |   | $ | 1,846,798 |   |
| Interest  receivable                                                               |       | 2,970                 |       | 1,582 |   |
| Net overriding  royalty interest in oil and gas properties                         |       | 380,905,000           |       | 380,905,000 |   |
| Less: accumulated amortization                                                     |       | (380,902,063          | )          | (380,901,952 | ) |
| Total assets                                                                       |       | $                     | 802,981    |   | $ | 1,851,428 |   |
| LIABILITIES AND TRUST  CORPUS                                                      |       |                  |       |   |   |
| Reserve for trust  expenses                                                        |       | $                     | 800,044    |   | $ | 1,848,380 |   |
| Distributions  payable                                                             |       | —                |       | — |   |
| Trust corpus  (71,980,216 units of beneficial interest authorized and outstanding) |       | 2,937                 |       | 3,048 |   |
| Total liabilities and  trust corpus                                                |       | $                     | 802,981    |   | $ | 1,851,428 |   |

 

**STATEMENTSOF CHANGES IN TRUST CORPUS**

| ** **                                       | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                       | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| Trust corpus,  beginning of year                 |       | $                                           | 3,048      |   | $ | 11,127 |   | $ | 11,127 |   |
| Distributable  income                            |       | —                                      |       | — |   | — |   |
| Distributions to  unitholders                    |       | —                                      |       | — |   | — |   |
| Amortization of  net overriding royalty interest |       | (111                                        | )          | (8,079 | ) | — |   |
| Trust corpus, end of  year                       |       | $                                           | 2,937      |   | $ | 3,048 |   | $ | 11,127 |   |

 

The accompanying notes arean integral part of these financial 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 or“JPMorgan” by mergers to the original name of the Trustee, Texas Commerce BankNational Association.

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

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

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

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

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

(e)   the Trust will terminate upon the first to occur of the followingevents: (i) the total amount of cash received per year by the Trust foreach of three successive years commencing after December 31, 1987 is lessthan ten times one-third of the total amount payable to the Trustee ascompensation for such three-year period (the “Termination Threshold”) or (ii) avote by holders of a majority of the outstanding units in favor of termination.Amounts earned by the Trustee as compensation were approximately $360,000,$204,000 and $148,000 for the years 2006, 2005 and 2004, respectively. Asdescribed further in “Business—Legal Proceedings and Status of the Trust” below,the Termination Threshold was met in the three consecutive years ending December 31,2004. Upon termination of the Trust, the Trustee will sell for cash all theassets held in the Trust estate and make a final distribution to unitholders ofany funds remaining after all Trust liabilities have been satisfied.

*The Partnership*

The Partnership was created to receive and hold a netoverriding royalty interest (the “Royalty”) in ten producing and 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”). Subsequentto the Merger, Pioneer owns and operates its assets through PNR and is also themanaging general partner of the Partnership.

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

*Legal Proceedingsand Status of the Trust*

Hurricane Katrina**struckthe Gulf of Mexico in August 2005. PNR has notified the Trust of itscurrent assessments regarding damages from Hurricanes Katrina and Rita toproduction facilities for properties in which the Trust has an interest. Theoperator of the West Delta properties has informed PNR that the West Deltaproperties have been shut in since August 27, 2005 due to damage to theplatform, the pipeline and the sales terminal. The operator has notified PNRthat they expect production at West Delta to resume during the second quarterof 2007.

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 “Business—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-year periodduring which it must sell all of the Trust properties. The Trust Indentureprovides that such properties must be sold for cash and not for any otherconsideration. The Trustee expects that the sale process will be open to anypersons desiring to participate, but, as is customary, access to informationand participation may be limited to persons who execute confidentialityagreements regarding information provided by the working interest owners. TheTrustee may also require bidders to identify themselves clearly and torepresent or evidence sufficient financing in order to participate, as theTrustee expects payment will be required promptly after the close of biddingwithout any financing conditions. Accordingly, the auction may not be a “public”auction in the sense that it may not be open to anyone who does not satisfythese requirements. The Trustee is currently reviewing a potential onlinebidding process for participants in order to provide current public informationon bidding to the marketplace. The Trustee will also determine a duration ofbidding 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. (referred to below in this Note collectively withPioneer Natural Resources Company, as “Pioneer”); Woodside Energy(USA), Inc. (“Woodside”); and JPMorgan, as Trustee of the Mesa OffshoreTrust (Case No. GN501113) (the “Lawsuit”). The Lawsuit is currently beforethe 334th Judicial District of Harris Country, Texas(the “Court”). MHLP’s Original Petition alleges Pioneer and Woodside are liablefor various actions, including (1) a wrongful farmout by Pioneer toWoodside of the Brazos A-39 Lease, (2) a wrongful delay by Pioneer inproducing the Brazos A-39 Lease and the Midway #5 well drill thereon,(3) fraudulent accounting practices by Pioneer, (4) breach of fiduciaryduty by Pioneer, (5) aiding and abetting breach of fiduciary duty byWoodside, (6) misapplication of Trust property by Pioneer,(7) conspiracy to misapply fiduciary property by Woodside and Pioneer,(8) common law fraud by Pioneer, (9) gross negligence by Pioneer, and(10) breach of the conveyance agreement by Pioneer. As described below,MHLP later added claims against the Trustee for (1) an accounting, and(2) breach of fiduciary duty. The remedies MHLP seeks include(a) reconstruing the Trust Indenture to determine that the Trust is notterminated because there has or should have been production that would havegenerated revenues to extend the life of the Trust, (b) requiring theTrustee to pursue certain claims, or to allow MHLP to pursue such claims,(c) setting aside any farmouts by Pioneer in which there have been 

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conveyances to an allegedaffiliate of Pioneer, (d) the removal of JPMorgan as Trustee, (e) thereturn or forfeiture of compensation to JPMorgan, (f) monetary damagesagainst Pioneer, Woodside and JPMorgan, and (g) unspecified exemplarydamages against all defendants.

MHLP’s Original Petition did not contain any claimsagainst the Trustee, except to enjoin the Trustee from terminating the Trustduring the pendency of the Lawsuit. In April 2005, the Trustee voluntarilyentered into an agreement with MHLP whereby the Trustee would not terminate theTrust without first giving MHLP at least sixty days written notice. Thisagreement allowed MHLP time to obtain documents and discovery from Pioneer andWoodside, and allowed the Trustee time to investigate the claims asserted byMHLP against Pioneer and Woodside to determine if they had any merit and, mostimportantly, whether they would benefit the Trust. During the six month periodbetween April and October 2005, the Trustee conducted an independentinvestigation including: numerous meetings and discussions with the parties;reviewing the relevant documents with the Trustee’s counsel; employingindependent reservoir engineers to evaluate the reserves in which the Trust hasan interest; engaging independent joint venture auditors to examine theaccounting records of the operator, Pioneer, relating to revenues and expensesallocated to the Partnership’s interests; and obtaining from both MHLP andPioneer their respective legal analyses of the challenged farmout.

Throughout 2005, the parties also anticipated that theMidway #5 well on the Brazos A-39 Lease that is the primary subject of theLawsuit would go into production. Given the vast discrepancy between thereserves claimed by the MHLP and those projected by Pioneer for the Midway #5well, actual production results would significantly impact the Trustee’sassessment of whether the Trust was better off with the cost-free overridecreated by the Pioneer/Woodside farmout, or the prior cost-burdened net profitsinterest that MHLP seeks to restore through the Lawsuit. Unfortunately,Hurricane Katrina struck the Gulf of Mexico in August 2005 and delayed thecommencement of production until 2006.

Faced with this post-Katrina situation, the Trusteeurged all the parties to consent to a bifurcated trial of the farmout issue onan expedited basis. The Trustee proposed to MHLP that if the Court determinedthat the farmout was not valid and that restoring the net profit interest wouldbenefit the Trust, then the Trust would reimburse MHLP’s reasonable attorneys’fees, up to $100,000, and the Trustee would allow MHLP’s counsel to representthe Trust in prosecuting the damages portion of the case. Conversely, if MHLPwere to lose on the expedited determination of the farmout issue, and in theabsence of more evidence to support any ancillary claims, then MHLP woulddismiss the other claims and would not be reimbursed, and the Trustee wouldmove forward to terminate the Trust.

While the Trustee, Pioneer, and Woodside all agreed toan expedited trial of the farmout issues, MHLP balked. Contrary to theassertions of MHLP and the Intervenor Plaintiffs identified below, the Trusteenever agreed that the claims asserted by MHLP against Pioneer and Woodside “hadmerit”—the Trustee simply stated that the farmout issue might meritadjudication at that time to determine (1) if MHLP was legally correct,and (2) if setting aside the farmout would benefit the Trust.

When MHLP refused to agree to an expedited andbifurcated trial as proposed by the Trustee, the Trustee informed MHLP that theTrustee’s investigation of MHLP’s allegations beyond the farmout issues failedto convince the Trustee of either their merit or that pursuing those claims andincurring the related legal fees and expenses would benefit the Trust.Moreover, the Trustee informed MHLP that the Trustee’s independent jointventure auditors and reservoir engineers had not found any evidence to date tosupport any of MHLP’s allegations.

It was at this point, in November 2005, in themidst of the Trustee’s negotiations with MHLP to obtain an agreed adjudicationof MHLP’s claims, that MHLP alleged for the first time that the Trustee had aconflict of interest because of JPMorgan’s long-standing lending relationshipwith Pioneer. Although it is clear under the Trust Indenture, the Texas TrustAct, and relevant case law that JPMorgan is not 

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precluded, by holding theposition of Trustee, from pursuing commercial banking activities not involving Trustfunds, MHLP amended its petition and asserted claims against the Trustee onNovember 28, 2005.

Although MHLP’s claims against the Trustee weremeritless, to avoid any further assertion that the Trustee could notimpartially evaluate MHLP’s claims, on November 30, 2005, JPMorganannounced its intention to resign as Trustee, effective January 31, 2006.On December 13, 2005, the lawsuit was transferred to the 334th Judicial District Court of Harris County,Texas. At a hearing on January 27, 2006 in the Harris County Court, theCourt denied MHLP’s motion for a temporary injunction to remove JPMorgan asTrustee and appoint a principal of MHLP, Timothy Roberson, as a temporaryTrustee. At the Court’s suggestion, JPMorgan agreed to continue as Trustee,until such time as a substitute trustee was found that fulfilled thequalifications of Trustee stated in the Trust Indenture. Since that hearing,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 December 8, 2006, Dagger-Spine HedgehogCorporation (“Dagger-Spine”) filed a petition to intervene in the Lawsuit as aPlaintiff, alleging claims virtually identical to MHLP. Another group ofunitholders, led by Keith A. Wiegand, (together with Dagger-Spine, the“Intervenors”) also filed on March 9, 2007 a petition to intervene asplaintiffs in the Lawsuit, incorporating and adopting the same claims assertedby MHLP.

On January 26, 2007, the Trustee reached aconditional settlement of the claims asserted by MHLP and the Intervenorsagainst Pioneer and Woodside. The conditional settlement is set forth in theMutual Release and Settlement Agreement dated as of January 26, 2007 (the“Conditional Settlement Agreement”). The Trustee filed a motion for approval ofthe Conditional Settlement Agreement with the Court on January 30, 2007.

The Conditional Settlement Agreement is the product ofextensive investigations and negotiations by the Trustee. In 2006, after theCourt denied MHLP’s attempt to remove JPMorgan as Trustee, the parties pursuedformal discovery in the Lawsuit. During this period, the Trustee continued toevaluate the merits of the alleged claims against Pioneer and Woodside. Acentral allegation by MHLP and the Intervenors is that Pioneer and Woodsidedelayed the commencement of production from the well drilled pursuant to thePioneer-Woodside Farmout—the Midway #5 well on the Brazos A-39 Lease. Woodsideand Pioneer witnesses have given sworn testimony in depositions about thecommercial and technical reasons for the delays in bringing the well on line.The well commenced production in April 2006. After this time, the Trusteeinstructed its independent petroleum reserve engineers to evaluate how theproduction results and projected production from the well might affect thevalue of the Trust’s interests. The Trustee’s independent engineers determinedthat the initial data regarding projected production from the well did notwarrant a material change in prior assessments of the value of the Trust’sassets.

Pioneer subsequently reported to the Trustee thatproduction from the well was suspended in July 2006 due to mercurycontamination identified at downstream facilities where the production from thewell is commingled with production from other wells. An updated evaluation fromthe Trustee’s independent petroleum reserve engineers estimated that revenuesfrom future production from the well likely would not exceed the costs ofdrilling and completing the well. Accordingly, if the Partnership’s interest inthe underlying lease had remained, or was, a cost-burdened net profitsinterest, instead of the cost-free overriding royalty interest the Partnershipheld as a result of the Pioneer-Woodside Farmout, the Partnership would nothave received, or would not receive, any payments from this production, and theTrust accordingly would not have received any associated distributions.Further, the production data did not support reserves of the size asserted byMHLP and the Intervenors. The well resumed production in February 2007.

Under the Conditional Settlement Agreement, Pioneerhas agreed to assign to the Trust an interest confirming its right to a 4.5%cost-free overriding royalty interest in the Brazos A-39 Lease until payout of 

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the Midway #5 well, and toassign to the Trust an interest in the Brazos A-39 Lease, to be effective fromand after payout if payout occurs, equal to a 45% net profits interest. Pioneerwould also agree to pay for and satisfy approximately $1.4 million of plugging,abandonment, and decommissioning costs relating to several of the assignedRoyalty Properties that Pioneer has informed the Trustee would otherwise beallocated to the Partnership’s Royalty. Finally, Pioneer and the Trustee haveagreed that Pioneer shall arrange for the sale of all assets of the Partnershipas provided for under the Trust Indenture on, or as soon as practical after,July 1, 2007, or on an earlier date as set forth in the proposedsettlement. The Conditional Settlement Agreement, if approved by the Court,would settle all claims in the Lawsuit that the Trust or the Partnership has ormight have against Pioneer and Woodside and any claims that Pioneer andWoodside might have against the Trust or the Partnership.

Based on the information available to the Trustee andits analysis outlined above, the Trustee believes that the benefits receivedunder the Conditional Settlement Agreement outweigh the potential benefits thatmay be achieved by the Trust litigating any of the asserted claims againstPioneer and Woodside, which would require the Trust to incur and assume therisk of further significant litigation costs. As a result, the Trustee believesthe Conditional Settlement Agreement is in the best interest of the unitholdersof the Trust. The Trustee has executed the Conditional Settlement Agreement andis recommending to the Court that the agreement be approved.

The Conditional Settlement Agreement is subject tocertain conditions, including approval by the Court. The Court has currentlyscheduled a hearing on the approval for May 21, 2007. MHLP and theIntervenors are not signatories or parties to the settlement and they, or otherunitholders of the Trust, may comment or object to the settlement. Thesettlement is not final until approved by the Court. If the Court approves theproposed settlement, it will enter an order that approves the settlement anddismisses the Lawsuit with prejudice as to all claims that may be brought onbehalf of the Trust, either by the Trustee or by unitholders seeking to assertclaims on behalf of themselves or the Trust, against Pioneer and Woodside basedon the facts asserted in the Lawsuit.

The Trustee will make thefull detail of the underlying data of the December 31, 2006 reserve reportavailable for use in connection with the sale of the Partnership’s RoyaltyProperties as part of the Trust termination. For more information regarding theestimated remaining life of each of the Royalty Properties, the estimatedfuture net revenues of the Royalty Properties and information relating tofarm-outs of interests on the Royalty Properties based on information providedby PNR to D&M, see pages 21 and 22 of this Form 10-K and Note 6in the Notes to Financial Statements included elsewhere in this Form 10-K.The final distribution to unitholders will be an amount net of funds requiredto satisfy all Trust liabilities.

*Timing ofLiquidation*

The Trust Indenture provides that the Trust willterminate if the total amount of cash per year received by the Trust fallsbelow certain levels for each of three successive years. As a result ofcontinued declines in production on Royalty Properties nearing the end of theirestimated productive lives, Royalty income received by the Trust in 2002, 2003and 2004 fell below the Termination Threshold prescribed by the TrustIndenture. Under the proposed Conditional Settlement Agreement, Pioneer and theTrustee have agreed that Pioneer shall arrange for the sale of all assets ofthe Partnership as provided for under the Trust Indenture on, or as soon aspractical after, July 1, 2007, or on an earlier date as set forth in theproposed settlement. The Trustee filed a motion for approval of the ConditionalSettlement Agreement with the court on January 30, 2007.

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.

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

**(3)**   Basisof Accounting

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

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

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

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

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

The instrumentsconveying the Royalty provide that the working interest owner will calculateand pay the Partnership each month an amount equal to 90% of the net proceedsfor the preceding month. Generally, net proceeds means the excess of theamounts received by the working interest owner from sales of oil and gas fromthe Royalty Properties plus other cash receipts over operating and capitalcosts incurred.

As of December 31,2006, PNR has advised the Trustee that there is a deficit balance due PNR of approximately$1.4  million which will be deducted from any future gross proceeds in theRoyalty Properties, which will reduce future Royalty revenue. See Note 1 “LegalProceedings and Status of the Trust” for terms of the contractual settlementagreement that, if approved would substantially eliminate the deficit balance. Inaddition, no Royalty income will be distributed to unitholders until theTrustee recoups Trust expenses being paid from the reserve that the Trustee hasestablished for anticipated future general and administrative expenses. As of December 31,2006 and 2005, $1,199,956 and $151,620, respectively, will be recouped by theTrustee from future Royalty income before Trust distributions will resume.

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

| ** **                                                 | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                 | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| General and  administrative costs incurred during the year |       | $                                           | 1,223,271  |   | $ | 824,691 |   | $ | 567,461 |   |
| (Deductions from)  additions to reserve for Trust Expenses |       | (1,048,336                                  | )          | 1,456,428 |   | (562,968 | ) |
| General and  administrative costs as reported              |       | $                                           | 174,935    |   | $ | 2,281,119 |   | $ | 4,493 |   |

 

**(4)**   Distributionsto Unitholders

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

**(5)**   FederalIncome Taxes

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

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

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

Estimates of the proved oil and gas reservesattributable to the Royalty as of December 31, 2006 and 2005, are based ona report prepared by DeGolyer and MacNaughton (“D&M”). The 2004 report is basedon a report prepared by PNR. The estimates were prepared in accordance withguidelines 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 numerousuncertainties inherent in estimating the quantities and value of provedreserves and in projecting the future rates of production and timing ofexpenditures. The reserve data below 

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representestimates only and should not be construed as being exact. Moreover, thediscounted 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 reservevolumes attributable to the Royalty are shown in order to comply withrequirements of the SEC. There is no precise method of allocating estimates ofphysical quantities of reserve volumes between PNR and the Partnership, sincethe Royalty is not a working interest and the Partnership does not own and isnot entitled to receive any specific volume of reserves from the Royalty. The quantitiesof reserves attributable to the Partnership have been and will be affected bychanges in various economic factors utilized in estimating net revenues fromthe Royalty Properties, as well as any exploration activities which may beconducted by PNR. Therefore, the estimates of reserve volumes set forth beloware to a large extent hypothetical and differ in significant respects fromestimates of reserves attributable to a working interest.

The future net revenuescontained in the previously mentioned reserve report have not been reduced forfuture general and administrative expenses of the Trust, which are expected toapproximate $1,200,000 annually. The general and administrative expenses of theTrust may increase for the remaining duration of the Trust, depending on theamount of royalty income, increases in accounting, engineering, legal, andother professional fees and other factors.

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, 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 |   |
| Revisions of previous  estimates             |       |                         | 206        |             |       | (71,476 | ) |
| Extensions, discoveries  and other additions |       |                         | —     |             |       | — |   |
| Production                                   |       |                         | (359       | )                |       | (28,517 | ) |
| December 31, 2006                       |       |                         | 10,613     |             |       | 360,062 |   |
| Proved Developed  Reserves:                  |       |                         |       |             |       |   |   |
| December 31, 2003.                      |       |                         | 11,111     |             |       | 432,679 |   |
| December 31, 2004.                      |       |                         | 5,960      |             |       | 174,510 |   |
| December 31, 2005.                      |       |                         | 10,766     |             |       | 460,055 |   |
| December 31, 2006.                      |       |                         | 10,613     |             |       | 360,062 |   |

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(See Notes on followingpage.)

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

| ** **                                                                      | ** ** | **December 31,**   | ** ** |
|---------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                      | ** ** | **2006**                | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                      | ** ** | **(In thousands)** | ** ** |
| Ninety percent of  future gross proceeds                                        |       | $2,588                  |       | $ | 4,625 |   | $ | 1,808 |   |
| Less ninety percent of—                                                    |       |                    |       |   |   |   |   |
| Future operating costs                                                          |       | —                  |       | (65 | ) | (469 | ) |
| Future capital costs, net of amounts previously accrued                         |       | (1,411                  | )          | — |   | — |   |
| Deficit due PNR                                                                 |       | —                  |       | — |   | (59 | ) |
| Future Royalty  income                                                          |       | 1,177                   |       | 4,560 |   | 1,280 |   |
| Discount at 10%  per annum                                                      |       | (409                    | )          | (738 | ) | (176 | ) |
| Standardized measure of  future Royalty income from proved oil and gas reserves |       | $                       | 768        |   | $ | 3,822 |   | $ | 1,104 |   |
|                                                                                 |            |                         |            |  |  |  |  |  |  |  |

 

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

| ** **                                    | ** ** | **Years Ended December 31,** | ** ** |
|-----------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                    | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                    | ** ** | **(In thousands)**                     | ** ** |
| Standardized  measure at beginning of year    |       | $                                           | 3,822      |   | $ | 1,104 |   | $ | 1,573 |   |
| Revisions of previous estimates               |       | (861                                        | )          | 3,311 |   | (752 | ) |
| Net changes in prices and production costs    |       | (1,141                                      | )          | 422 |   | 126 |   |
| Extensions, discoveries and other additions   |       | —                                      |       | 1,160 |   | — |   |
| Changes in estimated future development costs |       | (1,288                                      | )          | — |   | — |   |
| Royalty income                                |       | (146                                        | )          | (2,285 | ) | — |   |
| Accretion of discount                         |       | 382                                         |       | 110 |   | 157 |   |
| Net changes in standardized measure           |       | (3,054                                      | )          | 2,718 |   | (469 | ) |
| Standardized measure at  end of year          |       | $                                           | 768        |   | $ | 3,822 |   | $ | 1,104 |   |

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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)**   Selected QuarterlyFinancial Data (Unaudited)

| ** **                     | ** ** | **Summarized Quarterly Results** | ** ** |
|--------------------------------|------------|--------------------------------------------|------------|
| ** **                     | ** ** | **Three Months Ended**           | ** ** |
| ** **                     | ** ** | **March 31**                          | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| 2006:                          |       |                                       |       |   |   |   |   |   |   |   |   |
| Royalty income                 |       | $                                          | 40,765     |   | $ | 73,780 |   |   | $ | 31,097 |   |   | $ | — |   |
| Distributable  income          |       | $                                          | —     |   | $ | — |   |   | $ | — |   |   | $ | — |   |
| Distributable  income per unit |       | $                                          | —     |   | $ | — |   |   | $ | — |   |   | $ | — |   |
| 2005:                          |       |                                       |       |   |   |   |   |   |   |   |   |
| Royalty income                 |       | $                                          | 173,460    |   | $ | 505,409 |   |   | $ | 288,534 |   |   | $ | 1,317,512 |   |
| Distributable  income          |       | $                                          | —     |   | $ | — |   |   | $ | — |   |   | $ | — |   |
| Distributable income per  unit |       | $                                          | —     |   | $ | — |   |   | $ | — |   |   | $ | — |   |

 

 

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**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

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

We have audited the accompanying statements of assets,liabilities and trust corpus of Mesa Offshore Trust as of December 31,2006 and 2005, and the related statements of distributable income and changesin trust corpus for each of the years in the three-year period ended December 31,2006. These financial statements are the responsibility of the Trustee. Our responsibilityis to express an opinion on these financial statements based on our audits.

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

As described in Note 3, these financialstatements were prepared on the basis of cash receipts and disbursements asprescribed by the Securities and Exchange Commission, which is a comprehensivebasis of accounting other than accounting principles generally accepted in theUnited States of America.

In our opinion, the financial statements referred toabove present fairly, in all material respects, the assets, liabilities andtrust corpus of Mesa Offshore Trust as of December 31, 2006 and 2005, andthe distributable income and changes in trust corpus for each of the years inthe three-year period ended December 31, 2006, 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 and 2004fell 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,TexasJune 15, 2007**

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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 “—Trust unitholders and the Trustee have no control the operation or developmentof the Royalty Properties and have little influence over operation ordevelopment” 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.

*Changes in InternalControl 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.**                 Directors,Executive Officers and Corporate Governance.

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.

**Section 16(a)Beneficial Ownership Reporting Compliance**

**TheTrust has no directors or officers. Accordingly, only holders of more than 10%of the Trust’s Units are required to file with the SEC initial reports ofownership of Units and reports of changes in such ownership pursuant to Section16 under the Securities Exchange Act of 1934. Based solely on a review of thesereports, the Trust believes that the applicable reporting requirements ofSection 16(a) of the Securities Exchange Act of 1934 were complied with for alltransactions which occurred in 2006.**

**Item 11.**                 ExecutiveCompensation.

Not applicable.

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

***(a)****         **Security Ownership of Certain BeneficialOwners.*

| 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/A(Amend No. 6) filed on December 14, 2005. These units of beneficial interest ofthe Issuer (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.

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*(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, and Director Independence.

See Item 3. LegalProceedings and Item 1. Business “—Legal Proceedings and Status of the Trust”and “—Timing of Liquidation” for a description of legal proceedings and relatedtransactions among the Trustee, the Trust and certain unitholders of the Trust.

**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.

Thefollowing table presents fees for professional audit services rendered by KPMGLLP for the audit of the Mesa Offshore Trust financial statements for 2006 and2005 and fees billed for other services rendered by KPMG LLP.

| ** **          | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------|------------|----------|------------|----------|------------|
| Audit fees(1)       |       | $        | 125,000    |     | $          | 100,000 |   |
| Audit-related  fees |       | —   |       | —   |       |
| Tax fees(2)         |       | 25,000   |       | 25,000   |       |
| All other fees      |       | —   |       | —   |       |
| Total fees          |       | $        | 150,000    |     | $          | 125,000 |   |

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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 2006 related to 2005 tax work and paid in 2005 relatedto 2004 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         |   |   |

 

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**(a)(2)****                   Schedules**

Schedules have beenomitted because they are not required, not applicable or the informationrequired has been included elsewhere herein.

(**a)(3)****                   Exhibits**

(JPMorgan Chase Bank,N.A., is successor by mergers to the original name of the Trustee, TexasCommerce Bank National Association)
|      | ** ** | ** **                                                                                                                                                                                                                                                                                                        | ** ** | **SEC File or  Registration  Number** | ** ** | **Exhibit  Number** | ** ** |
|------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------|------------|---------------------|------------|
| 4(a) |       | *Mesa Offshore  Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National  Association, as Trustee, dated December 15, 1982                                                                                                                                                                |       |                                            | 2-79673    |                |       |   | 10 | (gg) |   |
| 4(b) |       | *Overriding  Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty  Partnership, dated December 15, 1982                                                                                                                                                                                   |       |                                            | 2-79673    |                |       |   | 10 | (hh) |   |
| 4(c) |       | *Partnership  Agreement between Mesa Offshore Management Co. and Texas Commerce Bank  National Association, as Trustee, dated December 15, 1982                                                                                                                                                              |       |                                            | 2-79673    |                |       |   | 10 | (ii) |   |
| 4(d) |       | *Amendment to  Partnership Agreement between Mesa Offshore Management Co., Texas Commerce  Bank National Association, as Trustee, and Mesa Operating Limited  Partnership, dated December 27, 1985 (Exhibit 4(d) to  Form 10-K for year ended December 31, 1992 of Mesa Offshore  Trust) |       |                                            | 1-8432     |                |       |   | 4 | (d) |   |
| 4(e) |       | *Amendment to  Partnership Agreement between Texas Commerce Bank National Association, as  Trustee, and Mesa Operating dated as of January 5, 1994  (Exhibit 4(e) to Form 10-K for year ended  December 31, 1993 of Mesa Offshore Trust)                                                 |       |                                            | 1-8432     |                |       |   | 4 | (e) |   |
| 10.1 |       | *Mutual Release  and Settlement Agreement dated January 26, 2007 (Incorporated by reference to  Exhibit 10.1 to Form 8-K filed on January 31, 2007)                                                                                                                                                               |       |                                            | 1-8432     |                |       |   | 10.1 |   |   |
| 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* |
| June 15, 2007 | * *             | *The Bank of New York Trust Company, N.A.,  as attorney-in-fact for the Trustee* |

 

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

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**EXHIBITINDEX**
| EXHIBIT  NUMBER | ** ** | ** ** | ** ** | **SEC File or  Registration  Number**                                                                                                                                                                                                                                                                   | ** ** | **Exhibit  Number** | ** ** |
|-----------------|------------|------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|
|            | 4          | (a)        |       | *Mesa Offshore  Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National  Association, as Trustee, dated December 15, 1982                                                                                                                                                                |       |                | 2-79673    |   |   |   | 10 | (gg) |   |
|            | 4          | (b)        |       | *Overriding  Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty  Partnership, dated December 15, 1982                                                                                                                                                                                   |       |                | 2-79673    |   |   |   | 10 | (hh) |   |
|            | 4          | (c)        |       | *Partnership  Agreement between Mesa Offshore Management Co. and Texas Commerce Bank  National Association, as Trustee, dated December 15, 1982                                                                                                                      |       |                | 2-79673    |   |   |   | 10 | (ii) |   |
|            | 4          | (d)        |       | *Amendment to  Partnership Agreement between Mesa Offshore Management Co., Texas Commerce  Bank National Association, as Trustee, and Mesa Operating Limited  Partnership, dated December 27, 1985 (Exhibit 4(d) to  Form 10-K for year ended December 31, 1992 of Mesa Offshore  Trust) |       |                | 1-8432     |   |   |   | 4 | (d) |   |
|            | 4          | (e)        |       | *Amendment to  Partnership Agreement between Texas Commerce Bank National Association, as  Trustee, and Mesa Operating dated as of January 5, 1994  (Exhibit 4(e) to Form 10-K for year ended  December 31, 1993 of Mesa Offshore Trust)                                                 |       |                | 1-8432     |   |   |   | 4 | (e) |   |
|            | 10.1       |       |       | *Mutual Release  and Settlement Agreement dated January 26, 2007 (Incorporated by  reference to Exhibit 10.1 to Form 8-K filed on January 31, 2007)                                                                                                                                                     |       |                | 1-8432     |   |   |   | 10.1 |   |   |
|            | 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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