10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM                                TO                                 

Commission file number 1-8432

Mesa Offshore Trust
(Exact Name of Registrant as Specified in Its Charter)

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

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

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange On Which Registered
None	None

Securities registered pursuant to Section 12(g) of the Act:
Units of beneficial interest
(Title of Class)

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such 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 ý    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer ý
(Do not check if a smaller reporting company) Smaller reporting company o

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o    No ý

         The aggregate market value of 71,980,216 Units of Beneficial Interest in Mesa Offshore Trust held by non-affiliates of the registrant at the closing sales price on June 30, 2008, of $0.25 was approximately $17,995,054.

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

         As of March 31, 2009, 71,980,216 Units of Beneficial Interest were outstanding in Mesa Offshore Trust.

DOCUMENTS INCORPORATED BY REFERENCE: None.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	3
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	26
Item 2.	Properties	26
Item 3.	Legal Proceedings	26
Item 4.	Submission of Matters to a Vote of Security Holders	26
PART II
Item 5.	Market for the Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	27
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 8.	Financial Statements and Supplementary Data	36
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	53
Item 9A.	Controls and Procedures	53
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	55
Item 11.	Executive Compensation	55
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	55
Item 13.	Certain Relationships and Related Transactions, and Director Independence	56
Item 14.	Principal Accounting Fees and Services	57
PART IV
Item 15.	Exhibits, Financial Statement Schedules	58
SIGNATURES		61

FORWARD-LOOKING STATEMENTS

        This Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-K, including without limitation the statements under "Business—Timing of Liquidation," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the financial statements of the Trust regarding the future net revenues of the Trust, are forward-looking statements. Although the Trustee believes, based in large part on information and statements provided to it by Pioneer Natural Resources USA, Inc., the Managing General Partner of the Partnership, that the expectations reflected in such forward-looking statements provided by it are reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-K, including, without limitation in conjunction with the forward-looking statements included in this Form 10-K. A consolidated summary description of principal risk factors that could cause actual results to differ is also set forth in this Form 10-K under "Item 1A. Risk Factors." All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements.

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PART I

Item 1.    Business.

DESCRIPTION OF THE TRUST

        The Mesa Offshore Trust (the "Trust"), created under the laws of the State of Texas, maintains its offices at the office of the Trustee, JPMorgan Chase Bank, N.A. (the "Trustee" or "JPMorgan"), 919 Congress Avenue, Austin, Texas 78701. The telephone number of the Trust is 1-800-852-1422. JPMorgan was formerly known as The Chase Manhattan Bank and is the successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association. JPMorgan Chase & Co. and The Bank of New York Company ("BNY") announced in April 2006 an agreement pursuant to which BNY would acquire a portion of JPMorgan Chase & Co.'s corporate trust business in exchange for BNY's consumer small business and middle market banking business. This transaction did not include any transfer by JPMorgan of its obligations as Trustee of this Trust.

        The Trustee does not maintain a website for filings by the Trust with the U.S. Securities and Exchange Commission ("SEC"). Electronic filings by the Trust with the SEC are available free of charge through the SEC's website at www.sec.gov.

        The principal asset of the Trust consists of a 99.99% interest in the Mesa Offshore Royalty Partnership (the "Partnership"). The Trust was created on December 28, 1982, effective December 1, 1982, when Mesa Petroleum Co. conveyed to the Partnership certain overriding royalty interests (collectively, the "Royalty") carved out of Mesa Petroleum Co.'s existing working interests in ten producing and non-producing oil and gas leases offshore Louisiana and Texas (the "Royalty Properties"). The Partnership was formed for the purpose of receiving and holding the Royalty, receiving the proceeds from the Royalty, paying the liabilities and expenses of the Partnership and disbursing remaining revenues to the Trustee and Mesa Offshore Management 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 operator and the managing general partner of the Royalty Properties. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("PNRC"), formerly a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. ("PNR") (successor to Mesa Operating Co.), a wholly owned subsidiary of PNRC (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, PNR owns and operates its assets through PNRC and is also the managing general partner of the Partnership. PNR and PNRC are referred to hereinafter collectively as "Pioneer." As hereinafter used in this report, the term PNR generally refers to the operator of the Royalty Properties, unless otherwise indicated. See "—Legal Proceedings and Status of the Trust" and "—Timing of Liquidation" for additional information regarding Pioneer and the Trust.

        Units of beneficial interest ("units") in the Trust were issued on December 28, 1982 to Mesa Petroleum Co. shareholders, who received one unit for each share of Mesa Petroleum Co. common stock held.

        The terms of the Mesa Offshore Trust Indenture (the "Trust Indenture") provide, among other things, that: (1) the Trust cannot acquire any asset other than its interest in the Partnership and cannot engage in any business or investment activity; (2) the Royalty can be sold in part or in total for cash upon approval of the unitholders or upon liquidation of the Trust; (3) the Trustee can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge the assets of the Trust to secure payment of the borrowing; (4) the Trustee will make quarterly distributions of cash available for distribution to the unitholders in January, April, July and October of each year; and (5) the Trust will terminate upon the first to occur of the following events: (i) the total amount of cash received per year by the Trust for each of three successive years commencing after December 31, 1987 is less than ten

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times one-third of the total amount payable to the Trustee as compensation for such three-year period (the "Termination Threshold") or (ii) a vote by holders of a majority of the outstanding units. Amounts paid to the Trustee as compensation were approximately $181,000, $177,000 and $360,000 for the years 2008, 2007 and 2006, respectively. As described further in "—Legal Proceedings and Status of the Trust", the Termination Threshold was met in each of the three consecutive years ending December 31, 2004. Due to pending litigation involving the Trust that challenges whether the Termination Threshold has in fact been met, the Trustee initially delayed the sale of the Partnership assets so that it could complete its investigation of the claims. Then, as the litigation developed and claims of conflict of interest were raised by certain unitholders, the Trustee further delayed liquidation in anticipation of reaching a resolution of the dispute. However, given the fact that (1) the litigation has lasted much longer than could have been anticipated, (2) it is very costly to continue to maintain the Trust, (3) there is a danger that the properties might revert back to the Minerals Management Service ("MMS"), and (4) the Trust has an opportunity to realize greater proceeds for the benefit of the Trust estate, the Trustee concluded that, in its business judgment, a public auction of the Partnership's oil and gas assets at this time was in the best interest of the Trust. Yet, at the public auction on March 18, 2009, no bids were submitted, so the Trustee is considering its options under the Trust Indenture and in light of the pending litigation. As part of the liquidation and eventual termination of the Trust, the Trustee will sell for cash all the assets held by the Partnership and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied. Pursuant to a stipulation announced in open court relating to the public auction, the Trustee has agreed to give 60-days notice before any final wind-up of the Trust.

        The terms of the First Amended and Restated Articles of General Partnership of the Partnership (the "Partnership Agreement") provide that the Partnership shall dissolve upon the occurrence of any of the following: (1) December 31, 2030; (2) the election of the Trustee to dissolve the Partnership; (3) the termination of the Trust; (4) the bankruptcy of the Managing General Partner; or (5) the dissolution of the Managing General Partner or its election to dissolve the Partnership; provided that the Managing General Partner shall not elect to dissolve the Partnership so long as the Trustee remains the only other partner of the Partnership.

        Under the Partnership Agreement and the instrument conveying the Royalty to the Partnership (the "Conveyance"), the Trust is entitled to its share (99.99%) of 90% of the Net Proceeds, as hereinafter defined, realized from the sale of the hydrocarbons as, if and when produced from the Royalty Properties. See "Description of Royalty Properties." The Conveyance provides for a monthly computation of Net Proceeds. "Net Proceeds" means the excess of Gross Proceeds, as hereinafter defined, received by PNR during a particular period over operating and capital costs and an amount to be recovered for future abandonment costs during such period. "Gross Proceeds" means generally the amount received by PNR from the sale of its share of minerals covered by the Royalty, subject to certain adjustments. Operating costs means, generally, costs incurred by PNR in operating the Royalty Properties, including capital costs. If operating and capital costs exceed the Gross Proceeds for any month, the excess plus interest thereon at the prime rate of the Bank of America plus one-half percent is recovered out of future Gross Proceeds prior to the making of further payment to the Trust. The Trust is not liable for any operating costs or other costs or liabilities attributable to the Royalty Properties or minerals produced therefrom. PNR, as owner of the working interest in the Royalty Properties, is required to maintain books and records sufficient to determine the amounts payable under the Royalty. Additionally, in the event of a controversy between PNR and any purchaser as to the correct sale price for any production, amounts received by PNR and promptly deposited by it with an escrow agent are not considered as having been received by PNR and therefore are not subject to being payable with respect to the Royalty until the controversy is resolved; but all amounts thereafter paid to PNR by the escrow agent will be considered amounts received from the sale of production. Similarly, operating costs include any amounts PNR is required to pay whether as a refund, interest or penalty to any purchaser because the amount initially received by PNR as the sales price was in excess

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of that permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation. Within 30 days following the close of each calendar quarter, PNR is required to deliver to the Trustee a statement of the computation of Net Proceeds attributable to such quarter.

        PNR is also authorized, as the Managing General Partner of the Partnership, to enter into farmouts of the Royalty Properties. Specifically, PNR may in its discretion, from time to time, elect to execute a farmout, in which event PNR shall have the right and option, but not the obligation to assign any portion of the Royalty Properties which PNR has made subject to such farmout, free and clear of the Royalty applicable thereto; provided, however, that with respect to any overriding royalty interest, production payment, leasehold or working interest, or any other interest in any Royalty Properties which is reserved by or acquired by PNR under such farmout (the "Retained Interests"), the Partnership shall be entitled to, and the Partnership's right with respect to such Retained Interests shall be limited to, an overriding royalty interest in each of the Retained Interests. However, if any Retained Interest is an interest which is convertible to another type of Retained Interest or any other interest, it is agreed that:

          (i)  As between PNR and the Partnership, PNR shall have the exclusive and full right and authority to exercise (or, in PNR's discretion, not to exercise) any such conversion option; and

         (ii)  If and when PNR should, in its discretion, elect to convert a Retained Interest to another type of Retained Interest or any other interest, then in such event the Partnership shall automatically become entitled to an overriding royalty interest (as herein computed) in any Retained Interest or any other interest acquired by PNR pursuant to such conversion election, and the Partnership shall have no further right with respect to, or interest in the Retained Interest which was so converted by PNR.

        The Royalty Properties are required to be operated by PNR in accordance with reasonable and prudent business judgment and good oil and gas field practices. PNR has the right to abandon any well or lease if, in its opinion, such well or lease ceases to produce or is not capable of producing oil, gas or other minerals in commercial quantities. PNR markets the production on terms deemed by it to be the best reasonably obtainable under the circumstances. See "Contracts." The Trustee has no power or authority to exercise any control over the operation of the Royalty Properties or the marketing of production therefrom.

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

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

DESCRIPTION OF THE UNITS

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

Distributions

        The Trustee determines for each month the amount of cash available for distribution for such month. Such amount (the "Monthly Distribution Amount") is equal to the excess, if any, of the cash distributed by the Partnership to the Trust during such month, plus any other cash receipts of the Trust during such month (other than interest earned on the Monthly Distribution Amount for any other month), over the liabilities of the Trust paid during such month, and adjusted for changes made by the Trustee during such month in any cash reserves established for the payment of contingent or future

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obligations of the Trust. The Monthly Distribution Amount for each month is payable to unitholders of record on the monthly record date (the "Monthly Record Date"), which is the close of business on the last business day of such month, or such later date as the Trustee determines is required to comply with legal or stock exchange requirements. However, to reduce the administrative expenses of the Trust, the Trust Indenture provides that the Trustee does not distribute cash monthly, but rather, during January, April, July and October of each year, distributes to each person who was a unitholder of record on a Monthly Record Date during one or more of the immediately preceding three months, the Monthly Distribution Amount for the month or months that he was a unitholder of record, together with interest earned on such Monthly Distribution Amount from the Monthly Record Date to the payment date.

Liability of Unitholders

        As regards to the unitholders, the Trustee is fully liable if the Trustee incurs any liability without ensuring that such liability will be satisfiable only out of the Trust assets (regardless of whether the assets are adequate to satisfy the liability) and in no event out of amounts distributed to, or other assets owned by unitholders. However, under Texas law, it is unclear whether a unitholder would be jointly and severally liable for any liability of the Trust in the event that all of the following conditions were to occur: (1) the satisfaction of such liability was not by contract limited to the assets of the Trust; (2) the assets of the Trust were insufficient to discharge such liability; and (3) the assets of the Trustee were insufficient to discharge such liability. Although each unitholder should weigh this potential exposure in deciding whether to retain or transfer his units, the Trustee is of the opinion that because of the passive nature of the Trust assets, the restrictions on the power of the Trustee to incur liabilities and the required financial net worth of any trustee, the imposition of any liability on a unitholder is extremely unlikely.

Federal Income Tax Matters

        This section is a summary of certain federal income tax matters of general application as of the date of this report. Except where indicated, the discussion below describes general federal income tax considerations applicable to individuals who are citizens or residents of the United States. Accordingly, the following discussion has limited application to domestic corporations and persons subject to specialized federal income tax treatment, such as regulated investment companies and insurance companies. It is impractical to comment on all aspects of federal, state, local and foreign laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in the units as they relate to the particular circumstances of every unitholder. Federal income taxation is a highly complex matter that may be affected by many considerations. Each unitholder is encouraged to consult its own tax advisor with respect to its particular circumstances and the advisability of its ownership of units.

        This summary is based on current provisions of the Internal Revenue Code of 1986, as amended (the Code), existing and proposed Treasury Regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the Internal Revenue Service (the "IRS"). No assurance can be provided that the statements set forth herein (which do not bind the IRS or the courts) will not be challenged by the IRS or will be sustained by a court if so challenged.

Classification of the Trust

        The federal income tax consequences to the unitholders of owning units depend on whether the Trust is classifiable as a grantor trust, a non-grantor trust, or a corporation. The Trustee reports on the basis that the Trust is a grantor trust. Based on its recent audit policy, the IRS is expected to concur

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with such action. No IRS ruling has been received with respect to the Trust, however, and no court case has been decided involving identical facts and circumstances. It is possible, therefore, that the IRS will assert on audit that the Trust is taxable as a corporation and that a court might agree with that assertion. The following discussion assumes that the Trust is classified as a grantor trust and not as an association taxable as a corporation. As a grantor trust the Trust will incur no federal income tax liability and each unitholder will be treated as owning an interest in the Partnership.

        The Trustee assumes that some Trust Units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust ("WHFIT") for U.S. federal income tax purposes. JPMorgan Chase Bank, N.A. ("Trustee" or "JPMorgan"), 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, is the representative of the Trust that will provide tax information beginning with the 2008 tax year in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT.

Income and Depletion

        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, interest income is portfolio income. Administrative expense is an investment expense.

        Generally, prior to the Revenue Reconciliation Act of 1990, the transferee of an oil and gas property could not claim percentage depletion with respect to production from the property if it was "proved" at the time of the transfer. This rule is not applicable in the case of transfers of properties after October 11, 1990. Thus, unitholders who acquired units after that date are entitled to claim an allowance for percentage depletion with respect to Royalty income attributable to these units to the extent that this allowance exceeds cost depletion as computed for the relevant period.

Backup Withholding

        Distributions from the Trust 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 his taxpayer identification number or the IRS notifies the Trust that the taxpayer identification number provided by the unitholder is incorrect.

Sale of Units

        Generally, except for recapture items, the sale, exchange or other disposition of a unit will result in capital gain or loss measured by the difference between the tax basis in the unit 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 gas property is treated as ordinary income up to the amount of intangible drilling and development costs incurred and depletion claimed to the extent it reduced the taxpayer's basis in the property. Under this provision, depletion attributable to a unit acquired after 1986 will be subject to recapture as ordinary income upon disposition of the unit or upon disposition of the oil and gas property to which the depletion is attributable. The balance of any gain or any loss will be capital gain or loss if the unit was held by the unitholder as a capital asset, either long-term or short-term depending on the holding period of the unit. This capital gain or loss will be long-term if a unitholder's holding period exceeds one year at the time of sale or exchange. Capital gain or loss will be short-term if the unit has not been held for more than one year at the time of sale or exchange. The long-term capital gain rate applied to most capital assets with a holding period of more than one year is 15%, but that rate is currently scheduled to expire on December 31, 2010. Without Congressional action, for taxable years beginning on or after January 1, 2011, the long-term capital gain rate is scheduled to increase to 20%. The deductibility of capital losses is subject to certain limitations.

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Non-U.S. Unitholders

        In general, a unitholder who is a nonresident alien individual or which is a foreign corporation, each a "non-U.S. unitholder" for purposes of this discussion, will be subject to tax on the gross income (without taking into account any deductions, such as depletion) produced by the Royalty at a rate equal to 30% or, if applicable, at a lower treaty rate. This tax will be withheld by the Trustee and remitted directly to the United States Treasury. A non-U.S. unitholder may elect to treat the income from the Royalty as effectively connected with the conduct of a United States trade or business under provisions of the Code or pursuant to any similar provisions of applicable treaties. Upon making this election a unitholder is entitled to claim all deductions with respect to that income, but he must file a United States federal income tax return to claim these deductions. This election once made is irrevocable unless an applicable treaty allows the election to be made annually. However, that effectively connected taxable income is subject to withholding at the highest applicable tax rate, 35% for individual non-US unitholders.

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

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

Tax-Exempt Organizations

        The Royalty and interest income should not be unrelated business taxable income so long as, generally, a unitholder did not incur debt to acquire a unit or otherwise incur or maintain a debt that would not have been incurred or maintained if the unit had not been acquired. Legislative proposals have been made from time to time which, if adopted, would result in the treatment of Royalty income as unrelated business taxable income. Each tax-exempt unitholder is encouraged to consult its own tax advisor with respect to the treatment of royalty income.

LEGAL PROCEEDINGS AND STATUS OF THE TRUST

Status of the Trust

        The Trust Indenture provides that the Trust will liquidate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of insufficient production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture. The Trustee had previously taken steps to begin the process of liquidating the Trust; however, the legal proceedings described herein challenge whether the Termination Threshold has in fact been met and thus affected the liquidation process, such that the Trustee initially delayed the sale of the Partnership's oil and gas assets in efforts to investigate and resolve the claims. Now, due to the continuation of the litigation into its fourth year, the related cost to the Trust, the threat that the properties might revert back to the MMS, and the opportunity to realize greater proceeds for the benefit of the Trust estate, the Trustee concluded that a public auction of the Partnership's oil and gas assets was in the best interest of the Trust at this time, and the Court allowed a public auction of these assets to go forward. See "—Timing of Liquidation" below. However, at the public auction conducted on March 18, 2009, there were no bids submitted. The Trustee is considering its options under the Trust Indenture and in light of the pending litigation. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no control over the occurrence of the Termination Threshold or its consequences.

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However, pursuant to a stipulation announced in open court relating to the public auction, the Trustee has agreed to give 60-days notice before any final wind-up of the Trust.

        The Trust Indenture provides the Trustee a two-year period during which it must sell all of the assets of the Partnership; but, in light of the pending litigation and the results from the recent public auction, the Trustee cannot predict the timing of the sale of the assets. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee expects that any future sale process will be open to any persons desiring to participate, but, as is customary, access to information and participation may be limited to persons who execute confidentiality agreements regarding information provided by the working interest owners. The Trustee may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a "public" auction in the sense that it may not be open to anyone who does not satisfy these requirements.

Legal Proceedings

        On April 11, 2005, MOSH Holding, L.P. ("MOSH") filed an Original Petition in the District Court of Travis County, Texas, 250th Judicial District, against PNRC; PNR; Woodside Energy (USA), Inc. ("Woodside"); and JPMorgan, as Trustee of the Mesa Offshore Trust (Case No. GN501113) (the "Lawsuit"). The Lawsuit is currently before the 334th Judicial District of Harris Country, Texas (the "Court"). MOSH's Original Petition alleged Pioneer and Woodside are liable for various actions, including (1) a wrongful farmout by Pioneer to Woodside of the Brazos A-39 Lease, (2) a wrongful delay by Pioneer in producing the Brazos A-39 Lease and the Midway #5 well drilled thereon, (3) fraudulent accounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aiding and abetting breach of fiduciary duty by Woodside, (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, MOSH later added claims against the Trustee for (1) an accounting, and (2) breach of fiduciary duty. The remedies MOSH seeks include (a) reconstruing the Trust Indenture to determine that the Trust is not terminated because there has or should have been production that would have generated revenues to extend the life of the Trust, (b) requiring the Trustee to pursue certain claims, or to allow MOSH to pursue such claims, (c) setting aside any farmouts by Pioneer in which there have been conveyances to an alleged affiliate of Pioneer, (d) the removal of JPMorgan as Trustee, (e) the return or forfeiture of compensation to JPMorgan, (f) monetary damages against Pioneer, Woodside and JPMorgan, and (g) unspecified exemplary damages against all defendants.

        MOSH's Original Petition did not contain any claims against the Trustee, except to enjoin the Trustee from terminating the Trust during the pendency of the Lawsuit. In April 2005, the Trustee entered into an agreement with MOSH whereby the Trustee would not sell the Trust assets without first giving MOSH 60-days written notice. This agreement allowed MOSH time to obtain documents and discovery from Pioneer and Woodside, and allowed the Trustee time to investigate the claims asserted by MOSH against Pioneer and Woodside to determine if they had any merit and, most importantly, whether the claims would benefit the Trust. During the six month period between April and October 2005, the Trustee conducted an independent investigation including: numerous meetings and discussions with the parties; reviewing the relevant documents with the Trustee's counsel; employing independent reservoir engineers to evaluate the reserves in which the Trust has an interest; engaging independent joint venture auditors to examine the accounting records of the operator, Pioneer, relating to revenues and expenses allocated to the Partnership's interests; and obtaining from both MOSH and Pioneer their respective legal analyses of the challenged farmout.

        Throughout 2005, the parties also anticipated that the Midway #5 well on the Brazos A-39 Lease that is the primary subject of the Lawsuit would go into production. Given the vast discrepancy

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between the reserves claimed by MOSH and those projected by Pioneer for the Midway #5 well, actual production results would significantly impact the Trustee's assessment of whether the Trust was better off with the cost-free override created by the Pioneer-Woodside farmout, or the prior cost-burdened net profits interest that MOSH seeks to restore through the Lawsuit. Unfortunately, Hurricane Katrina struck the Gulf of Mexico in August 2005 and delayed the commencement of production until 2006.

        Faced with this post-Katrina situation in the fall of 2005, the Trustee urged all the parties to consent to a bifurcated trial of the farmout issue on an expedited basis. The Trustee proposed to MOSH that if the Court determined that the farmout was not valid and that restoring the net profits interest would benefit the Trust, then the Trust would reimburse MOSH's reasonable attorneys' fees, up to $100,000, and the Trustee would allow MOSH's counsel to represent the Trust in prosecuting the damages portion of the case. Conversely, if MOSH were to lose on the expedited determination of the farmout issue, and in the absence of more evidence to support any ancillary claims, then MOSH would dismiss the other claims and would not be reimbursed, and the Trustee would move forward to terminate the Trust.

        Although the Trustee, Pioneer, and Woodside all agreed to an expedited trial of the farmout issues, MOSH balked. Contrary to the assertions of MOSH and the Intervenor Plaintiffs, the Trustee never agreed that the claims asserted by MOSH against Pioneer and Woodside "had merit"—the Trustee simply stated that the farmout issue might merit immediate adjudication at that time to determine if MOSH was legally correct.

        When MOSH refused to agree to an expedited and bifurcated trial as proposed by the Trustee, the Trustee informed MOSH that the Trustee's investigation of MOSH's allegations beyond the farmout issues failed to convince the Trustee that pursuing those claims and incurring the related legal fees and expenses would benefit the Trust. Moreover, the Trustee informed MOSH that the Trustee's independent joint venture auditors and reservoir engineers had not found any evidence to date to support any of MOSH's damage allegations. Therefore, the Trustee informed MOSH that the Trustee's investigation indicated that the Trust was better off with the post-farmout cost-free overriding royalty interest than the pre-farmout cost-burdened net profits interest, so the funding of MOSH's efforts to set aside the farmout with Trust funds would not be in the best interest of the Trust.

        It was at this point, in November 2005, in the midst of the Trustee's negotiations with MOSH to obtain an agreed resolution of MOSH's claims, that MOSH alleged for the first time that the Trustee had a conflict of interest because of JPMorgan's long-standing lending relationship with Pioneer. Although it is clear under the Trust Indenture, the Texas Trust Act, and relevant case law that JPMorgan is not precluded, by holding the position of Trustee, from pursuing commercial banking activities not involving Trust funds, MOSH amended its petition and asserted claims against the Trustee on November 28, 2005.

        Although it responded that MOSH's claims against the Trustee were meritless, to avoid any further assertion that the Trustee could not impartially evaluate MOSH's claims, on November 30, 2005, JPMorgan announced 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, the Court denied MOSH's motion for a temporary injunction to remove JPMorgan as Trustee and appoint a principal of MOSH, Timothy Roberson, as a temporary Trustee. At the Court's suggestion, JPMorgan agreed to continue as Trustee, until such time as a substitute trustee was found that fulfilled the qualifications of Trustee stated in the Trust Indenture. Since that hearing, none of the parties have identified a willing qualified successor Trustee that is not also a lender under one of Pioneer's credit facilities (which status MOSH 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 MOSH. Another group of

10

unitholders, led by Keith A. Wiegand, (together with Dagger-Spine, the "Intervenors") also filed on March 9, 2007 a petition to intervene as plaintiffs in the Lawsuit, incorporating and adopting the same claims asserted by MOSH. MOSH and the Intervenors are referred to hereinafter as the "Plaintiffs."

        In 2006, after the Court denied MOSH's attempt to remove JPMorgan as Trustee, the parties pursued formal discovery in the Lawsuit. During this period, the Trustee continued to evaluate the merits of the alleged claims against Pioneer and Woodside. A central allegation by MOSH and the Intervenors is that Pioneer and Woodside delayed the commencement of production from the well drilled pursuant to the Pioneer-Woodside farmout—the Midway #5 well on the Brazos A-39 Lease. However, Woodside and Pioneer witnesses gave sworn testimony in depositions about the commercial and technical reasons for the delays in bringing the well on line. The well commenced production in April 2006. After production began, the Trustee instructed its independent petroleum reserve engineers to evaluate how the production results and projected future production from the well might affect the value of the Trust's interests. The Trustee's independent engineers determined that the initial production data from the well did not warrant a material change in prior assessments of the value of the Trust's assets.

        Pioneer subsequently reported to the Trustee that production from the well was suspended in July 2006 due to mercury contamination identified at downstream facilities where the production from the well is commingled with production from other wells. An updated evaluation from the Trustee's independent petroleum reserve engineers estimated that revenues from future production likely would not exceed the costs of drilling and completing the well. This confirmed that, if the Partnership's interest in the underlying lease had remained, or was, a cost-burdened net profits interest, instead of the cost-free overriding royalty interest the Partnership held as a result of the Pioneer-Woodside farmout, the Partnership would not have received, or would not receive, any payments from this production, and the Trust accordingly would not have received any associated distributions. Further, the production data did not support reserves of the size asserted by the Plaintiffs. The well resumed production in February 2007, but the well was shut in again on April 18, 2007 due to an increase in hydrogen sulfide content coincidental with an increase in water production. Pioneer implemented a hydrogen sulfide contingency plan, which was required and approved by the Mineral Management Service ("MMS"), including the installation of the necessary alarm and safety systems. The well was shut in October 4, 2008 after discovery of corrosion in the production separator on the host platform. A replacement production separator was installed on the host platform. The well was returned to production on March 19, 2009. The well is currently producing at approximately 1.4-1.7 MM/D with a gradually declining flowing tubing pressure. There can be no assurance regarding the longevity of the gas production on the 52C host platform. Blending with this gas is required to meet pipeline gas quality specifications.

        Given its conclusion that the Trust may be better off with the post-farmout override, and hoping to end this expensive litigation and liquidate the Trust per the Trust Indenture, the Trustee reached a conditional settlement on January 26, 2007 with Pioneer and Woodside of the claims asserted by the Plaintiffs against Pioneer and Woodside. The conditional settlement was set forth in the Mutual Release and Settlement Agreement dated as of January 26, 2007 (the "Pioneer/Woodside Settlement Agreement"). The Trustee filed a motion for approval of the Pioneer/Woodside Settlement Agreement with the Court on January 30, 2007. The Trustee believed that the Pioneer/Woodside Settlement Agreement was in the best interest of the unitholders, but the Plaintiffs opposed it, and on June 19, 2007, the Court issued an Order denying the Trustee's motion to approve the Pioneer/Woodside Settlement Agreement.

        In June and July 2007, Pioneer and Woodside filed motions with the Court that argued that the claims against them did not have merit as a matter of law. Pioneer's motion included an argument that the Plaintiffs do not have the legal right to sue Pioneer because the claims belong to the Trust, not the beneficiaries of the Trust. On October 19, 2007, the Trustee offered to assign to the Plaintiffs the

11

Trust's claims against Pioneer and Woodside, but the plaintiffs rejected that offer. Through their counsel, the Plaintiffs and the Trustee also began negotiating a resolution of the claims pending between them, and on October 26, 2007, the Trustee and the Plaintiffs informed the Court of an agreement in principle to settle.

        On December 3, 2007, the Trustee entered into a Settlement Agreement and Release with the Plaintiffs and additional Trust unitholders (the "Plaintiffs' Settlement Agreement"). Also on December 3, 2007, the Trustee and the Plaintiffs filed a Joint Motion for Approval of Settlement Agreement (the "Joint Motion"). In response to the Joint Motion, on December 21, 2007, Pioneer filed cross-claims against the Trustee seeking declaratory and injunctive relief to prevent certain aspects of the proposed settlement between the Trustee and the Plaintiffs. On January 14, 2008, the Trustee filed an answer to Pioneer's cross-claims, in which the Trustee denied the cross-claims in their entirety, stated that they were baseless, and set forth numerous affirmative defenses. On January 22, 2008, the Court issued an Order denying the Joint Motion. As a result, the conditions precedent to the Plaintiffs' Settlement Agreement could not be satisfied, and the Plaintiffs' Settlement Agreement became null and void. In addition to denying the Joint Motion, the Court also considered and denied in the same Order (i) the application by the Plaintiffs for the appointment of a temporary trustee and (ii) Pioneer's application for a temporary restraining order. As a result of the Court's denial of the Joint Motion, and the Court's denial of the Plaintiffs' application for the appointment of a temporary trustee, JPMorgan elected not to resign in order to avoid a vacancy, and continues to serve as Trustee. The Trustee continues to desire the appointment of a successor Trustee.

        On April 28, 2008, the Court issued a Docket Control Order, setting the trial date for December 8, 2008. On July 3, 2008, the Plaintiffs filed a Third Amended Petition, seeking, among other things, to add claims against the Partnership (though its partners Pioneer and the Trustee) and JPMorgan in an individual capacity. By order dated July 3, 2008, the Court denied Pioneer's pending motions for summary judgment, including Pioneer's challenge to Plaintiffs' standing. Pioneer then filed a petition for writ of mandamus to the Houston Fourteenth Court of Appeals on July 22, 2008, seeking to reverse the trial courts' ruling on standing. On September 25, 2008, the Houston Fourteenth Court of Appeals denied Pioneer's petition for writ of mandamus, and Pioneer filed a petition for writ of mandamus with the Supreme Court of Texas on October 1, 2008. On October 24, 2008, the group of unitholders led by Keith A. Wiegand filed a Motion for Non-Suit Without Prejudice, and the Court granted the motion on October 24, 2008. Thus, all references herein to "Plaintiffs" after the date of October 24, 2008 include only MOSH and Dagger-Spine. At a hearing before the Court on October 31, 2008, the Plaintiffs agreed to postpone the trial again, and the trial is now scheduled for April 13, 2009. The Supreme Court of Texas denied Pioneer's petition for writ of mandamus on November 21, 2008.

        By notice dated February 6, 2009, which the Trustee mailed to all unitholders of record on February 10, 2009, the Trustee announced that the Termination Threshold had been met and that, as a result, it had instructed Pioneer to sell the oil and gas assets of the Partnership at public auction on March 18, 2009. In addition, the Trustee announced that the sale would include all of Pioneer's interests in Brazos Block A-39. On March 3, 9, and 12, respectively, unitholders Gordon Stamper, Robert Miles, and Keith Wiegand—formerly part of the group of Intervenors led by Keith Wiegand (collectively, the "Individual Intervenors")—filed pro se motions with the Court, requesting to intervene in the Lawsuit. At the public auction on March 18, 2009, no bids were submitted. The Trustee is considering its options under the Trust Indenture and in light of the pending litigation. On March 25, 2009, Plaintiffs filed their Fourth Amended Original Petition, Application for Temporary Restraining Order, Temporary Injunction, Show Cause Order, and Permanent Injunction. As of the date of this report, the trial of the Lawsuit remains scheduled for April 13, 2009, but the Plaintiffs have filed a motion for continuance, and the Trustee anticipates that the trial will be reset.

        The Trustee will make the full detail of the underlying data of the December 31, 2008 reserve report available for use in connection with the sale of the Partnership's Royalty Properties as part of

12

the Trust termination. For more information regarding the estimated remaining life of each of the Royalty Properties, the estimated future net revenues of the Royalty Properties and information relating to farm-outs of interests on the Royalty Properties, see "—Description of Royalty Properties" in this Form 10-K and Note 8 in the Notes to Financial Statements included elsewhere in this Form 10-K. The final distribution to unitholders will be an amount net of funds required to satisfy all Trust liabilities.

TIMING OF LIQUIDATION

        The Trust Indenture provides that the Trust will liquidate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture.

        Due to pending litigation involving the Trust that challenges whether the Termination Threshold has in fact been met, the Trustee initially delayed the sale of the Partnership assets so that it could complete its investigation of the claims. Then, as the litigation developed and claims of conflict of interest were raised by certain unitholders, the Trustee further delayed liquidation in anticipation of reaching a resolution of the dispute. However, given the fact that (1) the litigation has lasted much longer than could have been anticipated, (2) it is very costly to continue to maintain the Trust, (3) there is a danger that the properties might revert back to the MMS, and (4) the Trust has an opportunity to realize greater proceeds for the benefit of the Trust estate, the Trustee concluded that, in its business judgment, a public auction of the Partnerships' oil and gas interests at this time was in the best interest of the Trust. However, at the public auction conducted on March 18, 2009, there were no bids submitted. The Trustee is considering its options under the Trust Indenture and in light of the pending litigation. Pursuant to a stipulation announced in open court relating to the public auction, the Trustee has agreed to give 60-days notice before any final wind-up of the Trust.

Trust Assets and Liabilities

        As a result of the triggering of the Termination Threshold effective January 1, 2005, the Trust is in the process of liquidation. The below table presents the assets of the Trust at their estimated fair value as of December 31, 2008:

		December 31, 2008
ASSETS
Cash and short term investments		$	69
Net overriding royalty interest in oil and gas properties			1,480,309
	Total assets		1,480,378
LIABILITIES
Reserve for Trust expenses		$	69
Trust expenses payable			270,595
Interest Payable			230,440
Note payable—JPMorgan			3,557,646
	Total liabilities		4,058,750
Net liabilities in process of liquidation		$	(2,578,372	)

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The net overriding royalty interest in oil and gas properties at December 31, 2008 reflects the Trustee's estimate of value (in the absence of third-party appraisals or evaluations), based on the Trust's share of future net revenues from the net overriding royalty interest in the properties as of December 31, 2008. This estimate is based on the Trustee's current assessment of the impact of selling existing assets based on current market conditions, and includes the following assumptions:

•

The Trust's estimated share of proved oil and gas reserve volumes at December 31, 2008, was derived from the reserve report prepared by DeGolyer and MacNaughton ("D&M"), independent petroleum engineering consultants.

•

Forward strip commodity prices on December 31, 2008. The decline in commodity prices has decreased the fair value of the net overriding royalty interest in oil and gas properties.

•

Discount rate of 10%.

•

Future income taxes were not taken into account.

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

        For all other assets presented in the above table, the Trustee believes that historical cost approximates fair market value due to the short-term nature of such assets. The Trustee will continue to reserve funds to recoup its previously established reserves to pay Trust expenses, which will primarily consist of expenses incurred by the Trustee to liquidate the Trust's assets. Any funds remaining after all expenses have been paid will be distributed to the unitholders.

        For more information regarding the estimated remaining life of each of the Royalty Properties, the estimated future net revenues of the Royalty Properties and information relating to farm-outs of interests on the Royalty Properties, see "—Description of Royalty Property" in this Form 10-K and Note 8 in the Notes to Financial Statements included elsewhere in this Form 10-K. The sale of the assets of the Trust estate may include the related rights to abandonment accruals made by PNR. As explained in "Regulation and Prices—Platform Abandonment and Removal." PNR can withhold from the Trust a reserve to cover its share of those future abandonment and removal costs; however, no funds have been withheld as of December 31, 2008.

DESCRIPTION OF ROYALTY PROPERTIES

Producing Acreage and Wells as of December 31, 2008

						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-39			5,760		954		—		1		—		.05
	Total		10,760		1,579		—		5		—		.55

(1)

Dual completions are counted as one well. For information regarding wells producing at December 31, 2008, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Status of the Trust—Properties producing as of December 31, 2008" in Item 7 of this Form 10-K. As of January 31, 2009, only the wells on Brazos A-39 and West Delta 61 were capable of producing.

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(2)

Net Producing Acres are calculated by multiplying gross producing acres by the net royalty interest (as defined by the Conveyance) attributable to the Trust for each property. The current net interests attributable to the Trust after giving effect to farmout agreements are described in Item 7 of this Form 10-K.



(3)

All wells on South Marsh Island 155 and 156 leases were plugged and abandoned in 2002. PNR abandoned the platform for these two properties in 2003. All wells were plugged and abandoned and the platform was abandoned on West Delta 62 during 2003 and the lease was relinquished.



(4)

All wells were plugged and abandoned and the platform was abandoned on Matagorda Island 624 during 2003 and the lease was relinquished.

Reserves

        A study of the proved oil and gas reserves attributable to the Partnership as of December 31, 2008, has been made by D&M, independent petroleum engineering consultants, in a letter (the "Reserve Report") attached as Exhibit 99(a) and incorporated herein by reference. The Reserve Report reflects estimated reserve quantities and future net revenue based upon estimates of the future timing of actual production without regard to when received in cash by the Trust, which differs from the manner in which the Trust recognizes and accounts for its Royalty income. The following tables are based on the information contained in the Reserve Report and summarize (1) estimates of the Trust's gross and net proved reserves as of December 31, 2008, and (2) the estimated future revenue and costs attributable to the Trust's royalty interest in the proved reserves, as of December 31, 2008, of the properties evaluated.

	Oil and Condensate (bbl)		Natural Gas (Mcf)
Gross Reserves Proved		79,016		3,034,618
Net Reserves Proved		6,082		213,299
			Proved ($)
Future Gross Revenue				1,493,534
Operating Expenses				—
Capital Costs				—
Future Net Revenue*				1,493,534
Present Worth at 10 Percent*				1,251,878

*

Future income tax expenses were not taken into account in the preparation of these estimates.

        For further information regarding the Net Overriding Royalty Interest, the Basis of Accounting for the Trust and Supplemental Reserve Information, see Notes 3, 4 and 8, respectively, in the Notes to Financial Statements contained in Item 8 of this Form 10-K.

        There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The preceding reserve data based on the Reserve Report represent estimates only and should not be construed as being exact. Reserve assessment is a subjective process of estimating the recovery from underground accumulations of gas and oil that cannot be measured in an exact way and estimates of other persons might differ materially from those of D&M. Accordingly, reserve estimates are often different from the quantities of hydrocarbons that are ultimately recovered.

15

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

        Moreover, the discounted present values in the Reserve Report should not be construed as the current market value of the estimated gas and oil reserves attributable to the Royalty Properties or the costs that would be incurred to obtain equivalent reserves, since a market value determination would include many additional factors. In accordance with applicable regulations of the SEC, estimated future net revenues were based, generally, on current prices and costs, whereas actual future prices and costs may be materially greater or less. The estimates in the Reserve Report use market prices as of December 31, 2008. These prices (having weighted average year end prices of $44.60 per barrel of oil and condensate and $5.71 per Mcf of natural gas as of December 31, 2008) were held constant over the estimated life of the Royalty Properties. These prices were influenced by seasonal demand for natural gas and may not be the most appropriate or representative prices to use for estimating future revenues or related reserve data. The average price of natural gas sold from the Royalty Properties during 2008 was $8.86 per Mcf, representing a combination of contract prices and spot market prices, while the average price of crude oil, condensate and natural gas liquids was $101 per barrel. See Management's Discussion and Analysis of Financial Condition and Results of Operations "—Financial and Operational Overview—Production and Price Review" of this Form 10-K.

        The following is a summary of the estimated remaining life for each of the Royalty Properties provided to the Trustee by D&M as of December 31, 2008. There are numerous uncertainties present in estimating the remaining productive lives for the Royalty Properties. The following summary represents an estimate only and should not be construed as being exact. The estimated remaining productive life of each property varies depending on the recoverable reserves and annual production assumed by D&M. In addition, future economic and operating conditions may cause significant changes in these estimates.

Property	Productive Life(1)(2)
West Delta 61	6 years
Brazos A-39	3 years

(1)

Under the Trust Indenture, the Trust is to liquidate and then terminate in the event the total amount of cash received per year by the Trust falls below certain levels. Accordingly, it would be possible for the Trust to terminate even though some of the Royalty Properties continued to have remaining productive lives. See "Business—Legal Proceedings and Status of the Trust" and see "Business—Timing of Liquidation."



(2)

Estimates of remaining lives may vary significantly from year to year.

        The future net revenues contained in the Reserve Report have not been reduced for future general and administrative costs and expenses of the Trust.

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

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CONTRACTS

General

        PNR has advised the Trust that during 2008 its offshore gas production was marketed under short-term contracts at spot market prices primarily to TOTAL S.A. PNR has further advised the Trust that it expects to continue to market its production under short-term contracts for the foreseeable future. Spot market prices for natural gas in 2008 were generally higher than spot market prices in 2007.

Market for Natural Gas

        The amount of cash distributions by the Trust is dependent on, among other things, the sales prices for natural gas produced from the Royalty Properties and the quantities of gas sold. The natural gas industry in the United States during the 1990's was affected generally by a surplus in natural gas deliverability in comparison to demand. Demand for gas declined during this period due to a number of factors including the implementation of energy conservation programs, a shift in economic activity away from energy intensive industries and competition from alternative fuel sources such as residual fuel oil, coal and nuclear energy. In late 2001 and early 2002, demand for natural gas increased as a result of the increase in clean burning natural gas fired power generation, the increase in the usage of electrical power fueled by the expanding U.S. economy and a return to seasonally cold winters. Annual wellhead prices generally increased from $2.95 per Mcf in 2002, increased to $5.09 per Mcf in 2003, to $5.49 per Mcf in 2004, to $5.65 in 2005, to $6.42 in 2006 but decreased to $6.39 in 2007 and $8.07 in 2008 according to the Natural Gas Monthly published by the Energy Information Administration of the Department of Energy.

        The seasonal nature of demand for natural gas and its effects on sales prices and production volumes may cause the amounts of cash distributions by the Trust to vary substantially on a seasonal basis. Generally, production volumes and prices are higher during the first and fourth quarters of each calendar year due primarily to peak demand in these periods. Because of the time lag between the date on which PNR receives payment for production from the Royalty Properties and the date on which distributions are made to unitholders, the seasonality that generally affects production volumes and prices is generally reflected in distributions to unitholders in later periods.

Competition

        The production and sale of gas from the areas in which the Royalty Properties are located is highly competitive and PNR has a number of competitors in these areas. PNR has advised the Trust that it believes that its competitive position in these areas is affected by price, contract terms and quality of service. PNR's business is affected not only by such competition, but also by general economic developments, governmental regulations and other factors.

Marketing of Liquids

        PNR generally reserves in its gas purchase contracts the right to extract condensate and other liquid and liquefiable hydrocarbons from all gas produced. PNR is currently selling the condensate and other liquids to purchasers under contracts with terms of one year or less.

REGULATION AND PRICES

General

        The production and sale of natural gas from the Royalty Properties are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by

17

price controls, taxes, conservation, safety, environmental and other laws relating to the petroleum industry, by changes in such laws and by constantly changing administrative regulations.

Operating Hazards and Uninsured Risks

        PNR's oil and gas activities are subject to all of the risks normally incident to exploration for and production of oil and gas, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to a variety of operating risks, such as hurricanes and other adverse weather conditions and lack of access to existing pipelines or other means of transporting production. Furthermore, offshore oil and gas operations are subject to extensive governmental regulations, including certain regulations that may, in certain circumstances, impose absolute liability for pollution damages, and to interruption or termination by governmental authorities based on environmental or other considerations. In accordance with customary industry practices, PNR carries insurance against some, but not all, of these risks. Losses and liabilities resulting from such events would reduce revenues and increase costs to the Trust to the extent not covered by insurance.

FERC Regulation

        In general, the FERC regulates the transportation of natural gas in interstate commerce by interstate pipelines. Over the course of approximately the previous decade, the FERC adopted regulations resulting in a restructuring of the natural gas industry. The principal elements of this restructuring were the requirement that interstate pipelines separate, or "unbundle," the various services offered on their systems into individual components, with all transportation services to be provided on a non-discriminatory basis, and the prohibition against an interstate pipeline providing gas sales services except through separately-organized affiliates. In various rulemaking proceedings following its initial unbundling requirement, the FERC has refined its regulatory program applicable to interstate pipelines in various respects, and it has announced that it will continue to monitor these regulations to determine whether further changes are needed. As to these various developments, the working interest owners have advised the Trust that the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.

State and Other Regulation

        State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements. Some states have implemented more stringent legislation in recent years to regulate gathering rates charged by gas gathering companies, but to date the effect to PNR in connection with the Royalty Properties has been minimal.

        Natural gas pipeline facilities used for the transportation of natural gas in interstate commerce are subject to Federal minimum safety requirements. These requirements, however, are not applicable to, inter alia,: (1) onshore gathering facilities outside: (i) the limits of any incorporated or unincorporated city, town, or village; and (ii) any designated residential or commercial area; or (2) pipeline facilities on the Outer Continental Shelf ("OCS") upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator. See 49 C.F.R. § 192.1(b). We are informed that the Royalty Properties are located in Federal waters on the OCS. The standards governing pipeline safety have undergone recent changes and it is possible that future changes in the regulations and statutes may occur which may increase the stringency of the standards or expand the applicability of the standards to facilities not currently covered.

Environmental

        PNR's operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the

18

environment, including the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund"), the Solid Waste Disposal Act, the Clean Air Act, and the Federal Water Pollution Control Act. These laws and regulations, including their state counterparts, can impose liability upon the lessee under a lease for the cost of cleanup of discharged materials resulting from a lessee's operations or can subject the lessee to liability for damages to natural resources. Violations of environmental laws, regulations, or permits can result in civil and criminal penalties as well as potential injunctions curtailing operations in affected areas and restrictions on the injection of liquids into the subsurface that may contaminate groundwater. PNR maintains insurance for costs of cleanup operations, but it is not fully insured against all such risks. A serious release of regulated materials could result in the U.S. Department of the Interior requiring lessees under federal leases to suspend or cease operations in the affected area. In addition, the recent trend toward stricter standards and regulations in environmental legislation is likely to continue. For example, legislation has been proposed in Congress that would reclassify certain oil and gas production wastes as "hazardous wastes" which would subject the handling, disposal and cleanup of these wastes to more stringent requirements and result in increased operating costs for the Royalty Properties, as well as the oil and gas industry in general. State initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these initiatives could have a similar impact on the Royalty Properties.

        From time to time, federal and state environmental agencies propose regulations which could have a direct and material impact on PNR's operations. For example, under the Oil Pollution Act of 1990, as amended by the Coast Guard Authorization Act of 1996 (collectively, "OPA"), parties responsible for offshore facilities must establish and maintain evidence of oil-spill financial responsibility ("OSFR") for costs attributable to potential oil spills. OPA requires a minimum of $35 million in OSFR for offshore facilities located on the OCS. This amount is subject to upward regulatory adjustment up to $150 million. Responsible parties for more than one offshore facility are required to provide OSFR only for their offshore facility requiring the highest OSFR. In 1998, the MMS adopted regulations for establishing the amount of OSFR required for particular facilities. The amount of OSFR increases as the volume of a facility's worst-case oil spill increases. Accordingly, for facilities with worst-case spills of less than 35,000 barrels, only $35 million in OSFR is required; for worst-case spills of over 35,000 barrels, $70 million is required; for worst-case spills of over 70,000 barrels, $105 million is required; and for worst-case spills of over 105,000 barrels, $150 million is required. In addition, all OSFR below $150 million remains subject to upward regulatory adjustment if warranted by the particular operational, environmental, human health or other risks involved with a facility. Under this regulation, PNR is required to maintain $35 million in OSFR for its offshore facilities. PNR is maintaining its OSFR in this amount by insurance. Although the working interest owners have advised the Trust that current environmental regulation has had no material adverse effect on the working interest owners' present method of operations, the impact of the recently adopted regulatory changes, and of future environmental regulatory developments such as stricter environmental regulation and enforcement policies, cannot presently be quantified.

        In response to scientific studies suggesting that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to the warming of the Earth's atmosphere, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider, legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas "cap and trade" programs. These "cap and trade" programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants that emit more greenhouse gases than permitted by these programs, to acquire emission allowances from other businesses that emit greenhouse gases at levels lower than the limits specified by these programs and then surrender these allowances as a credit against such emissions. Depending on the particular program, we could be required to purchase and surrender such emission allowances, either for

19

greenhouse gas emissions resulting from our operations (e.g., compressor stations) or from the combustion of fuels (e.g., natural gas) that we process.

        Also, as a result of the United States Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases, including carbon dioxide, fall under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an "Advance Notice of Proposed Rulemaking" regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court's decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could also have an adverse affect on our cost of doing business and demand for the natural gas we process and transport.

Homeland Security

        The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. We have not yet determined the extent to which our facilities are subject to coverage under the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.

        PNR has advised the Trust that it is not involved in any administrative or judicial proceedings relating to the Royalty Properties arising under federal, state, or local environmental protection laws and regulations which would have a material adverse effect on the Trust's financial position or results of operations.

Platform Abandonment and Removal

        PNR is responsible for the abandonment and removal of its offshore drilling and production structures within one year after the cessation of production, although extensions can be requested. PNR can withhold from the Trust a reserve to cover its share of those future abandonment and removal costs; however, no funds have been withheld as of December 31, 2008. See Item 7 of this Form 10-K and Note 4 in the Notes to Financial Statements for amounts withheld as of December 31, 2008 and amounts to be withheld in the future.

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Item 1A.    Risk Factors.

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

         Natural gas and oil prices fluctuate due to a number of factors, and lower prices will reduce net proceeds available to the Trust and distributions to Trust unitholders.

        The Trust's quarterly distributions are highly dependent upon the prices realized from the sale of natural gas and oil, and a material decrease in these prices could reduce the amount of Trust distributions. Natural gas and oil prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and the working interest owners. Factors that contribute to price fluctuation include, among others: political disruption, war, or other armed conflict in oil producing regions, in particular the war in Iraq; worldwide economic conditions; weather conditions; the supply and price of foreign natural gas and oil; the level of consumer demand; the price and availability of alternative fuels; the proximity to, and capacity of, transportation facilities; and the effect of worldwide energy conservation measures.

        Moreover, government regulations, such as regulation of natural gas and oil transportation and price controls, can affect product prices in the long term.

        When natural gas and oil prices decline, the Trust is affected in two ways. First, net royalties are reduced. Second, exploration and development activity on the underlying properties may decline as some projects may become uneconomic and are either delayed or not undertaken. The volatility of energy prices reduces the predictability of future cash distributions to unitholders. Substantially all of the natural gas and natural gas liquids produced from the Royalty Properties is being sold on the spot market or under short-term contracts.

         The Trust is party to a Demand Promissory Note that may be called at any time, and the Trust may not have sufficient funds to repay amounts outstanding under this note or to make additional distributions to unitholders of the Trust.

        On September 28, 2007, the Trust entered into a Demand Promissory Note agreement with JPMorgan in order to cover portions of its operating expenses. The lender approved an uncommitted line of credit to the Trust in a principal amount not to exceed $3 million. As part of that agreement, JPMorgan pays the expenses on behalf of the Trust. JPMorgan may decline to fund any request of the Trust for borrowings at anytime, for any reason, including the event that JPMorgan has reason to believe that the Trust will not be able to satisfy its obligation to repay the Demand Promissory Note. Interest on the note is calculated at a rate per annum equal to Prime Rate plus two percent (2%), paid annually. The Demand Promissory Note is secured by a pledge of the Trust Estate, as that term is defined in the Trust Indenture, including without limitation the 99.99% general partnership interest in the Mesa Offshore Royalty Partnership owned by the Trust, pursuant to a Pledge Agreement dated September 29, 2007, as amended by the First Amendment to Pledge Agreement dated as of December 3, 2007, executed by the Trust for the benefit of the Lender.

        On December 3, 2007, JPMorgan, individually and as lender, entered into an Amended and Restated Promissory Note (the "Amended and Restated Note"), with the Trust as borrower, to amend the Demand Promissory Note to provide for, among other provisions, an extension of the stated maturity date of the Loans made pursuant to the Demand Promissory Note and the Amended and Restated Note until the earlier of (1) December 31, 2009, (2) 31 days after the Trust's receipt of any settlement proceeds, recovery or judgment in connection with the Lawsuit, (3) final liquidation of the Trust's assets, or (4) the Settlement Agreement is not approved by the Court. Additionally, the amendment provided that the Trust may continue to obtain loans under the note until the maturity

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date, as long as, the amount borrowed does not exceed $3 million and the loan is not in default. The amendment also provided that interest expense shall be due and payable on the maturity date.

        On August 25, 2008, the Trustee executed an amended and restated Demand Promissory Note that among other things increased the aggregate principal amount available for borrowing to $4 million and amended the definition of "Maturity Date" to delete the text relating to the failure of the Court to approve the prior Settlement Agreement in the Lawsuit.

        On January 28, 2009, the Trustee executed and delivered to the lender a Third Amended and Restated Promissory Note, dated as of January 12, 2009, increasing the principal amount available for borrowing, subject to the terms of such note, to $5 million. On January 28, 2009, the Trust and JPMorgan Chase Bank, N.A. also entered into a Third Amendment to Pledge Agreement, dated as of January 12, 2009, amending the definition of "Collateral" from the Second Amendment to the Pledge Agreement dated June 25, 2008 to include (1) all issued and outstanding general partnership interests by the Trust in the Partnership, together with any cash or property received in exchange or in substitution for such interests (collectively, the "Pledged Assets"), and any distributions received on such Pledged Assets or cash or property received upon any conversion or in exchange for such Pledged Assets; (2) all Additional Collateral (as defined therein) owned by the Trust; (3) all deposit accounts in the name of the Trust; (4) any consideration received or due to the Trust; and (5) all proceeds of any and all of the foregoing.

        Interest is payable at a base rate offered by JPMorgan as announced publicly at its principal office as its prime commercial lending rate, plus 2%. The rate effective as of December 31, 2008 was a Prime Rate of 3.25%, plus 2% for a combined rate of 5.25%.

        As of December 31, 2008, there was outstanding $3,557,646 of principal advanced for payment of Trust expenses together with $230,440 of accrued and unpaid interest expense. At December 31, 2008, the Trust had $442,354 available under this facility. Should the Trust fully utilize the funds available under the Demand Promissory Note, as amended, the Trustee will attempt to borrow additional money. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at all.

        The Trust Indenture prohibits the Trustee from making any distributions until these loans are repaid in full. Due to the uncertain timing of potential sales of the Royalty Properties in connection with the liquidation of the Trust and the outcome of pending litigation, and based on the estimated future net revenue and present worth of the Trust's interests in proved reserves made by the independent reserve engineer as of December 31, 2008, it is possible that amounts received in connection with any such sales of Royalty Properties, net of other amounts payable in accordance with the Partnership Agreement and other liabilities of the Trust, may not exceed amounts then outstanding under the Amended and Restated Note.

         Increased production and development costs for the Royalty will result in decreased Trust distributions.

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

        If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive net proceeds for those properties until future proceeds

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from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.

         Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both estimates of reserves and estimated future revenues to be too high or too low.

        The value of the units of beneficial interest of the Trust depends upon, among other things, the amount of reserves attributable to the Royalty and the estimated future value of the reserves. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions include:

•

historical production from the area compared with production rates from similar producing areas;

•

the assumed effect of governmental regulation;

•

assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures;

•

the availability of enhanced recovery techniques; and

•

relationships with landowners, working interest partners, pipeline companies and others.

        Changes in these factors and assumptions can materially change reserve estimates and future net revenue estimates.

        The reserve quantities attributable to the Royalty and revenues are based on estimates of reserves and revenues for the underlying properties. The method of allocating a portion of those reserves to the Trust is complicated because the Trust holds an interest, indirectly through the Partnership, in the Royalty and does not own a specific percentage of the natural gas reserves. Ultimately, actual production, revenues and expenditures for the underlying properties and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-downs of reserves.

        The Trustee also relies entirely on reserve estimates prepared by the independent reserve engineer engaged by the Trust based on information provided to the engineer by Pioneer. While the Trustee has no reason to believe the reserve estimates and related estimates of value included in this report are not accurate, to the extent additional information exists that could affect their reserve estimates, the estimated reserves in these reports and related estimates of value could also be too low.

         Estimates and accruals of costs by PNR may be greater or less than future estimated or actual costs.

        As discussed in Item 7 and Note 4 to the Notes to Financial Statements, at December 18, 2008, PNR informed the Trustee that there is no longer a deficit balance due for abandonment accrual for amounts expended and for projected future abandonment expenses for the properties in which the Trust has an interest.

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

        There are operational risks and hazards associated with the production and transportation of natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of natural

23

gas, releases of other hazardous materials, mechanical failures, cratering and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment of natural resources, or cleanup obligations. The occurrence of drilling, production or transportation accidents at any of the Royalty Properties will reduce Trust distributions by the amount of uninsured costs. These occurrences include blowouts, cratering, explosions and other environmental damage. Offshore activities are also subject to a variety of operating risks such as hurricanes and other weather disturbances. These accidents and other natural disasters may result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any uninsured costs would be deducted as a production cost in calculating net proceeds payable to the Trust.

         Terrorism and continued hostilities in the Middle East could decrease Trust distributions or 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 in response, cause instability in the global financial and energy markets. Terrorism, the war in Iraq and other sustained military campaigns could adversely affect Trust distributions or the market price of the Units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in natural gas prices, or the possibility that the infrastructure on which the operators developing the underlying properties rely could be a direct target or an indirect casualty of an act of terror.

         The operators of the working interests are subject to extensive governmental regulation.

        Offshore oil and gas operations have been, and in the future will be, affected by federal, state and local laws and regulations and other political developments, such as price or gathering rate controls and environmental protection regulations. These regulations and changes in regulations could have a material adverse effect on Royalty income payable to the Trust.

         The unitholders and the Trustee have no control over the operation or development of the Royalty Properties and have little influence over operation or development.

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

        PNR, as the current working interest owner, is under no obligation to continue operating the properties. Neither the Trustee nor the unitholders have the right to replace an operator.

         The Trustee relies upon the working interest owners and managing general partner for information regarding the Royalty Properties.

        The Trustee relies on the working interest owners and managing general partner for information regarding the Royalty Properties. The working interest owners alone control (i) historical operating data, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures, (iii) geological data relating to reserves, as well as related projections regarding production, operating expenses and capital expenses used in connection with the preparation of the reserve report, (iv) forward-looking information relating to production and drilling plans and (v) information regarding the Royalty Properties responsive to litigation claims. While the Trustee requests material information for use in periodic reports as part of

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its disclosure controls and procedures, the Trustee does not control this information and relies entirely on the working interest owners to provide accurate and timely information when requested for use in the Trust's periodic reports. The Trustee also relies on the managing general partner of the Partnership to collect certain information from the working interest owners and does not have any direct contact with the working interest owners other than the managing general partner. Under the terms of the Trust Indenture, the Trustee is entitled to rely, and in fact relies, on certain experts in good faith. While the Trustee has no reason to believe its reliance on experts is unreasonable, this reliance on experts and limited access to information may be viewed as a weakness as compared to the management and oversight of entity forms other than trusts.

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

        The working interest owner may at any time transfer all or part of the Royalty Property to another unrelated third party. Unitholders are not entitled to vote on any transfer, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the Royalty Properties will continue to be subject to the Royalty, but the net proceeds from the transferred property would be calculated separately and paid by the transferee. The transferee would be responsible for all of the obligations relating to calculating, reporting and paying to the Trust (through the Partnership) the Royalty on the transferred portion of the Royalty Properties, and the current owner of the Royalty Properties would have no continuing obligation to the Trust for those properties.

        The current working interest owner or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in termination of the Royalty relating to the abandoned well. Please see "Business—Legal Proceedings and Status of the Trust" and "Business—Timing of Liquidation" in Item 1 of this Form 10-K.

         The Royalty will be sold and the Trust terminated.

        Subject to the pending Lawsuit, the Trust will be liquidated and the Trustee will sell the Royalty, as the total amount of cash received per year by the Trust for each of three consecutive years ending December 31, 2004 was less than the Termination Threshold. Following this termination and liquidation, the net proceeds of any sale will be distributed to the unitholders, and unitholders will receive no further distributions from the Trust. We cannot assure you that any such sale will be on terms acceptable to all unitholders. See Item 1 of this Form 10-K under "Business—Legal Proceedings and Status of the Trust" and "Business—Timing of Liquidation."

         Trust assets are depleting assets and, if the working interest owners or other operators of the Royalty Properties do not perform additional development projects, the assets may deplete faster than expected.

        The net proceeds payable to the Trust are derived from the sale of depleting assets. Accordingly, the portion of the distributions to unitholders 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 will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of natural gas. If the operator of the Royalty Properties does not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust. For federal income tax purposes, depletion is reflected as a deduction, which is dependent upon the purchase price of a unit. Please see the section entitled "Business—Description of the Units—Federal Income Tax Matters" in Item 1 of this Form 10-K.

        Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of distributions to unitholders attributable to depletion may be considered a return of capital as

25

opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the Trust unitholders, which could reduce the market value of the Trust units over time. Eventually, properties underlying the Trust's Royalty will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds therefrom.

         Unitholders have limited voting rights.

        Voting rights as a unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of unitholders or for an annual or other periodic re-election of the Trustee. Unlike corporations which are generally governed by boards of directors elected by their equity holders, the Trust is administered by a corporate Trustee in accordance with the Trust Indenture and other organizational documents. The Trustee has extremely limited discretion in its administration of the Trust.

         Unitholders have limited ability to enforce the Trust's rights against the current or future owners of the Royalty Properties.

        The Trust Agreement and related trust law permit the Trustee, on behalf of the Trust, to sue the working interest owner in certain instances to compel it to fulfill the terms of the Conveyance of the Royalty. If the Trustee does not take appropriate action to enforce provisions of the Conveyance, the recourse of a unitholder would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Unitholders probably would not be able to sue the working interest owner directly.

         The limited liability of the Trust unitholders is uncertain.

        The Trust unitholders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a corporation's liabilities. The structure of the Trust does not include the interposition of a limited liability entity such as a corporation or a limited partnership which would provide further limited liability protection to Trust unitholders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to insure that such liabilities of the Trust are to be satisfied only out of Trust assets, under the laws of Texas, which are unsettled on this point, a holder of units may be jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets 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.    Unresolved Staff Comments.

        There were no unresolved Securities and Exchange Commission comments as of December 31, 2008.

Item 2.    Properties.

        Reference is made to "Business—Description of Royalty Properties" contained in Item 1 of this Form 10-K.

Item 3.    Legal Proceedings.

        Reference is made to "Business—Legal Proceedings and Status of the Trust" contained in Item 1 of this Form 10-K.

Item 4.    Submission of Matters to a Vote of Security Holders.

        There were no matters submitted to a vote of unitholders during the fourth quarter of 2008.

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PART II

Item 5.    Market for the Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

        The units of beneficial interest of the Trust were delisted from the Pacific Exchange effective May 18, 2001. The Trust units are currently eligible for trading on the OTC Bulletin Board under ticker symbol MOSH.OB. In 2008, the Trust had no Royalty income. No Royalty income will be distributed to the unitholders until the Trustee recoups Trust expenses being paid from the reserve that the Trustee has established for anticipated future expenses and any loans secured by the Trustee to pay Trust expenses are repaid in full. The high and low sales prices and distributions per unit for each quarter in the two years ended December 31, 2008 were as follows:

	2008						2007
	High		Low		Distribution Paid		High		Low		Distribution Paid
First Quarter	$	0.50	$	0.10	$	—	$	0.15	$	0.06	$	—
Second Quarter	$	0.41	$	0.17	$	—	$	0.12	$	0.07	$	—
Third Quarter	$	0.42	$	0.15	$	—	$	0.10	$	0.08	$	—
Fourth Quarter	$	0.50	$	0.17	$	—	$	0.40	$	0.05	$	—

        At March 31, 2009, the 71,980,216 units outstanding were held by 10,147 unitholders of record.

Item 6.    Selected Financial Data.

	2008		2007			2006			2005		2004
Royalty income	$	—	$	—		$	145,642		$	2,284,914	$	—
Distributable income	$	—	$	—		$	—		$	—	$	—
Distributable income per unit	$	—	$	—		$	—		$	—	$	—
Accumulated deficit at year end(1)	$	—	$	(1,477,002	)	$	(1,417,808	)	$	—	$	(59,035	)
Expenses Payable(2)		270,595		190,955			—			—		—
Trust Accrued Interest Expense		230,440		31,187			—			—		—
Note Payable—JPMorgan(3)	$	3,557,646	$	1,673,617		$	—		$	—	$	—
Total assets at year end	$	3,006	$	5,906		$	802,981		$	1,851,428	$	387,986

(1)

Accumulated deficit at year end represents amounts that will be deducted from future gross proceeds on the Royalty Properties, which will reduce future Royalty income. No Royalty income will be distributed to unitholders in the future until PNR recoups the accumulated deficit. On December 18, 2008, PNR informed the Trustee that there is no longer a deficit balance due for abandonment accrual for amounts expended and for projected future abandonment expenses for the properties in which the Trust has an interest.

(2)

The reserve for Trust expenses and advances under the Demand Promissory Note with JPMorgan were used to pay $1,886,932 of the Trust's general and administrative expenses of $1,966,572 for the year ended December 31, 2008 and $190,955 of accrued expenses from 2007. The Trust had unpaid expenses of $270,595 as of December 31, 2008. Interest income and the reserve for Trust expenses were used to pay $802,155 of the Trust's general and administrative expenses of $2,666,727 for the year ended December 31, 2007. The Trust had unpaid expenses of $190,955 as of December 31, 2007.

(3)

Based on the current general and administrative expenditures being incurred in connection with the litigation and the absence of Royalty income, the Trustee was required to borrow money in accordance with the Trust Indenture to fund Trust expenses. The Note payable at year end represents the amount due under the Demand Promissory Note entered into with JPMorgan on September 28, 2007 and amended on December 3, 2007 and August 25, 2008. The Trust Indenture prohibits the Trustee from making any distributions to unitholders until these loans are repaid in full.

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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

        The following review of the Trust's financial condition and results of operations should be read in conjunction with the financial statements and notes thereto.

Critical Accounting Policies

        The financial statements of the Trust do not include any adjustment as a result of the termination of the Trust as described in notes 1 and 2 and are prepared on the following basis:

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

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

        (c)   Trust general and administrative expenses are recorded in the month they accrue and are recoupable from Royalty income. Trust expenses payable and the note payable at December 31, 2008 are reported as a reduction in Trust Corpus.

        This basis for reporting distributable income is considered to be the most meaningful because distributions to the unitholders for a month are based on net cash receipts for such month. However, it will differ from the basis used for financial statements prepared in accordance with accounting principles generally accepted in the United States of America because, under such accounting principles, royalty income for a month would be based on net proceeds from sales for such month without regard to when calculated or received and interest income for a month would be calculated only through the end of such month, and accounting principles generally accepted in the United States may require a liquidation basis of accounting.

Status of the Trust

        Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties informed PNR that the West Delta properties were shut in since August 27, 2005 due to damage to the platform, the pipeline, and the sales terminal, until production at West Delta resumed at all four wells in the fourth quarter of 2007 at a combined production rate of 4.8 MMCFD. There are currently four wells producing on this block, and their combined rate is 1.2 MMCF/day and 200 barrels of oil per day.

        The Trust Indenture provides that the Trust will liquidate and terminate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture. The Trustee had previously taken steps to begin the process of liquidating the Trust; however the legal proceedings described herein challenge whether the Termination Threshold has in fact been met and thus affected the liquidation process, such that the Trustee initially delayed the sale of the Partnership's oil and gas assets in efforts to investigate and resolve the claims. Now, due to the continuation of the litigation into its fourth year, the related cost to the Trust, the threat that the properties might revert back to the MMS, and the opportunity to realize greater proceeds for the benefit of the Trust estate, the Trustee concluded that a public auction of the Partnership's oil and gas assets was in the best interest of the Trust at this time, and the Court allowed a public auction of these assets to go forward. See "Business—Timing of Liquidation" in Item 1 of this Form 10-K. However, at the public auction conducted on March 18, 2009, there were no bids

28

submitted. The Trustee is considering its options under the Trust Indenture and in light of the pending litigation. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no control over regarding the occurrence of the Termination Threshold or its consequences. However, pursuant to a stipulation announced in open court relating to the public auction, the Trustee has agreed to give 60-days notice before any final wind-up of the Trust.

        The Trust Indenture provides the Trustee a two-year period during which it must sell all of the assets of the Partnership; but in light of the pending litigation and the results from the recent public auction, the Trustee cannot predict the timing of the sales of the assets. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee expects that any future sale process will be open to any persons desiring to participate, but, as is customary, access to information and participation may be limited to persons who execute confidentiality agreements regarding information provided by the working interest owners. The Trustee may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a "public" auction in the sense that it may not be open to anyone who does not satisfy these requirements.

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

Properties producing as of December 31, 2008

Property	Number of Producing wells(1)		Estimated Productive Life(1)	Estimated Future Royalty Income(2)
West Delta No. 61		4	6 years	$	1,304,858
Brazos A-39		1	3 years	$	188,676

(1)

Information obtained from December 31, 2008 reserve report prepared by D&M.



(2)

Represents estimated future royalty income from the December 31, 2008 reserve report. Future royalty income was calculated using oil and gas spot prices in effect at December 31, 2008 of $44.60 per barrel and $5.71 per thousand cubic feet.

Properties abandoned or scheduled for abandonment as of December 31, 2008

Property	Status
Brazos A-7	Abandoned in 2005 (Newfield platform 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

*

Midway prospect tied-back to an existing platform operated by a third party.

29

Financial and Operational Review

        As discussed in Item 1 of this Form 10-K, PNR has advised the Trust that during 2008, its offshore gas production was marketed under short-term contracts at spot market prices primarily to TOTAL S.A. and that it expects to continue to market its production under short-term contracts for the foreseeable future. Spot market prices for natural gas were on the average higher in 2008 than spot market prices in 2007.

        The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of gas, crude oil, condensate and natural gas liquids produced from the Royalty Properties and the quantities sold. Substantial uncertainties exist with regard to future gas and oil prices, which are subject to fluctuations due to the regional supply and demand for natural gas and oil, production levels and 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.

        Below is a summary of Royalty income received on the Trust properties for each of the years ended December 31, 2008, 2007 and 2006:

	2008			2007			2006
Gross proceeds @ 90%	$	1,328,010		$	29,550		$	239,356
Operating expenditures @ 90%		(22,432	)		(88,649	)		(103,476	)
Change in abandonment estimate @ 90%		102,658			—			(1,400,139	)
Other proceeds (expenditures) @ 90%		112,780			—			(8,034	)
Net proceeds (deficit)		1,521,016			(59,099	)		(1,272,293	)
Increase (decrease) in deficit		(1,477,149	)		59,099			1,417,950
Net proceeds after deficit recovery	$	43,867			—			145,657
Royalty income (99.99%)(1)	$	—		$	—		$	145,642

(1)

Net proceeds after deficit recovery were not received by the Trust until January 2009, therefore no royalty income was recorded for this amount for the year ended December 31, 2008.

        Below is a summary of distributable income for the years ended December 31, 2008, 2007 and 2006:

	Years Ended December 31,
	2008			2007			2006
Royalty income	$	—		$	—		$	145,642
Interest income		—			5,080			29,293
General and administrative expenses		(—	)		(5,080	)		(174,935	)
Distributable income	$	—		$	—		$	—
Distributable income per unit	$	—		$	—		$	—
Accumulated deficit (as of period end)	$	(—	)	$	(1,477,002	)	$	(1,417,808	)

        The Trust had no distributable income in 2008, 2007 and 2006. The reserve for Trust expenses and advances under the Demand Promissory Note with JPMorgan were used to pay $1,886,932 of the Trust's general and administrative expenses of $1,966,572 for the year ended December 31, 2008 and $190,955 of accrued expenses from 2007. The Trust had unpaid expenses of $270,595 as of December 31, 2008 as compared to $190,955 as of December 31, 2007. The reserve for Trust expenses and interest income were used to pay $802,155 of the Trust's general and administrative expenses of

30

$2,666,727 for the year ended December 31, 2007. The Trust had unpaid expenses of $190,955 as of December 31, 2007. On September 28, 2007 the Trust entered into a Demand Promissory Note with JPMorgan which was amended on December 3, 2007 and August 25, 2008, in which loans will be advanced by the lender from time to time not to exceed $4 million. This Demand Promissory Note will be used to pay any unpaid administrative expenses related to the operation of the Trust. As of December 31, 2008, approximately $3,557,646 has been advanced to the Trust to pay Trust expenses. On January 28, 2009, the Trustee executed and delivered to JPMorgan a Third Amended and Restated Promissory Note, dated as of January 12, 2009, increasing the principal amount available for borrowing, subject to the terms of such note, to $5 million.

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

	Years Ended December 31,
	2008			2007			2006
General and administrative costs incurred during the year	$	1,966,572		$	2,666,727		$	1,223,271
Expenses paid by JPMorgan for prior period		190,955			—			—
(Deductions from) additions to reserve for trust expenses		(2,900	)		(797,075	)		(1,048,336	)
Total expenses paid by JP Morgan during current period		(1,884,032	)		(1,673,617	)		—
Unpaid trust expenses		(270,595	)		(190,955	)		—
General and administrative costs as reported	$	—		$	5,080		$	174,935

        General and administrative expenses of the Trust for 2008 decreased 26% to $1,966,569 for 2008 as compared to $2,666,727 for 2007. The decrease in general and administrative expenses in 2008 is primarily due to a decrease in legal fees in the pending litigation and expenditures related to the anticipated sale of Trust properties pursuant to the Trust's termination. General and administrative expenses of the Trust for 2007 increased 118% to $2,666,727 for 2007 as compared to $1,223,271 for 2006. The increase in general and administrative expenses in 2007 is primarily due to an increase in legal fees in the pending litigation as described in "Legal Proceedings." The Trust incurred additional expenditures in 2005 for 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 of certain historical expenditures and revenue receipts on Trust properties.

        Below is an operational review of the remaining producing Trust properties:

Brazos A-7 and A-39

	2008			2007			2006
Gross proceeds @ 90%	$	124,818		$	29,550		$	152,215
Operating expenditures @ 90%		(748	)		(60,705	)		(87,211	)
Change in abandonment estimate @ 90%		—			(373	)		(1,269,806	)
Capital expenditures @ 90%		—			—			—
Net proceeds (deficit)	$	124,070		$	(31,528	)	$	(1,204,802	)

        The Brazos A-7 and A-39 blocks continued to experience a decrease in natural gas production due to natural production decline. As of December 31, 2008, these two blocks had one well capable of

31

producing, the Brazos A-39 #5 well, which was shut-in during the first quarter of 2007 due to the detection of mercury. The Brazos A-7 No. B-1 well, operated by Newfield, was no longer producing as of December 31, 2006 and was abandoned in 2007. PNR previously entered into farmout agreements in 2003 for the Partnership's interest in both of these blocks so that two exploration prospects could be drilled and in which the Trust will retain an overriding royalty interest. The first prospect on Brazos A-7 was drilled during 2003 and was determined to be a dry hole. As such, the well was plugged and abandoned. In 2005, PNR performed abandonment procedures at the PNR operated Brazos A-7 and the A-39 blocks, 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. These abandonment procedures were substantially completed during 2006.

        The second exploration prospect, the Brazos A-39 #5 well, was drilled on Brazos A-39, which PNR announced as a discovery. A production test was completed in 2005. PNR, the operator on this property, informed the Trustee that the lower horizon of the prospect was determined to be non-commercial, while the middle horizon in the Big Hum 4 sand produced at 10,000 Mcf of gas per day during a seventeen hour flow test. This well came on line April 20, 2006. However, this well has been shut in from time to time since then as the operator has encountered and addressed hydrogen sulfide issues. The well has also produced a carbon dioxide content that exceeds pipeline specifications. This higher content requires the operator to mix production at the platform with production from other fields in order to transport the product. Production is being routed to the A-52C platform owned by Beryl Oil and Gas. That platform is being operated by Arena, which is also serving as the contract operator for the Midway property. The well was shut in July 21, 2006 by Williams Pipeline due to reported detection of mercury in the gas stream. Following the installation of vessels with mercury absorbing media and negotiation of the required agreements with the owner and operator of the Brazos A-52C host platform, the well was returned to production on February 13, 2007. The well was shut-in on April 18, 2007 due to an increase in hydrogen sulfide content coincidental with an increase in water production. Pioneer implemented a hydrogen sulfide contingency plan, which was required and approved by the Mineral Management Service ("MMS"), including the installation of the necessary alarm and safety systems. The well was shut in October 4, 2008 after discovery of corrosion in the production separator on the host platform. A replacement production separator was installed on the host platform. The well was returned to production on March 19, 2009. The well is currently producing at approximately 1.4-1.7 MM/D with a gradually declining flowing tubing pressure. There can be no assurance regarding the longevity of the gas production on the 52C host platform. Blending with this gas is required to meet pipeline gas quality specifications.

        Under the terms of a farmout agreement between PNR and Woodside, PNR farmed out to Woodside the undivided one-half interest previously burdened by the Partnership's net profits interest, but expressly providing that the farmed out interest would not be subject to the Partnership's net profits interest. PNR reserved a 10% overriding royalty interest, proportionately reduced to the interest conveyed, which interest, upon Woodside's recoupment of specified costs and expenses, would increase to 12.5%, proportionately reduced to the interest conveyed. The Partnership's net profits interest burdens the overriding royalty interest reserved by PNR. PNR has informed the Trustee that it believes this process is consistent with the terms of the original conveyance and with the handling of other farmout transactions involving lands burdened by the Partnership's net profits interest.

        PNR continues to own the undivided one-half interest not burdened by the Partnership's net profits interest and will participate in and operate the well as owner of that undivided one-half interest (subject to an agreement with Woodside to grant Woodside such interest in PNR's remaining undivided one-half interest to equalize those parties' participation in the well).

        PNR has noted to the Trustee that the farmout agreement with Woodside enabled the drilling costs of these prospects to be carried on the Partnership's interest in part by Woodside. PNR further noted that the Partnership's net profits interest would not have entitled the Trust (through the

32

Partnership) to payment until drilling costs and applicable interest were recovered, whereas the overriding royalty interest retained under the farmout agreement entitles the Trust (through the Partnership) to payments prior to the recoupment of expenses incurred by Woodside and PNR. As noted above, the first prospect on Brazos A-7 was determined to be a dry hole. Under the farmout agreement and related agreements, those drilling and abandonment costs have been born entirely by PNR and Woodside and are not subject to recoupment from any proceeds otherwise payable to the Partnership or the Trust. Similarly, the Partnership's current interest in the "Midway" prospect on Brazos A-39 will be entitled to payment 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

	2008			2007			2006
Gross proceeds @ 90%	$	1,203,192		$	—		$	87,141
Operating expenditures @ 90%		(21,684	)		(27,944	)		(16,265	)
Change in abandonment expenditures @90%		102,658			373			(130,333	)
Capital expenditures @ 90%		112,780			—			(8,034	)
Net proceeds (deficit)	$	1,396,946		$	(27,571	)	$	(67,491	)

        Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties informed PNR that the West Delta properties were shut in since August 27, 2005 due to damage to the platform, the pipeline, and the sales terminal, until production at West Delta resumed at all four wells in the fourth quarter 2007. There are currently four wells producing on this block, and their combined rate is 1.2 MMcf/day and 200 barrels of oil per day. The proceeds for the year ended December 31, 2006 consist of revenue adjustments related to prior periods received by the Trust during 2006.

        The PNR-operated wells ceased production in 2002, and the wells were plugged and abandoned by year-end with the facilities being completely abandoned during 2003. The only remaining wells on this block are in West Delta 61. PNR farmed out a portion of West Delta 61 to Stone Energy retaining a 12.5% (11.25% net to the Trust through the Partnership) overriding royalty interest. Those properties were sold to Maritech Resources Inc. effective October 1, 2007. Maritech began accounting for the properties on February 1, 2008.

Capital Expenditures

        PNR does not anticipate any significant capital expenditures on the Royalty Properties in the future. Due to the limited financial capacity of the Trust, PNR has advised that it intends to farm out the Partnership's interest in the blocks it believes may be produced economically, retaining an overriding royalty interest for the Partnership.

Other Proceeds

        During the third quarter of 2008, proceeds for salvage value were received on the Matagorda Island Block 624 of $57,335 and $55,445 for the South Marsh Island 155 Block.

33

Abandonment Expenditures

        The below table provides a rollforward of the abandonment and removal costs cash reserve that PNR has withheld from the Partnership and the Trust since January 1, 2004:

Balance, January 1, 2004	$	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	$	—
Balance, December 31, 2007	$	—
Balance, December 31, 2008	$	—

        In 2006, PNR exhausted the $348,066 cash reserve established as of December 31, 2005. In the third quarter of 2006, PNR revised their estimate of abandonment expenses incurred, but not recouped from the Partnership and expenses yet to be incurred for properties, in which the Partnership has an interest to approximately $1.4 million. This revision was caused by increased work necessary because of damages caused by Hurricane Katrina, and increased day rates for labor due to the high demand for labor following Hurricanes Katrina and Rita. As of March 31, 2008, PNR had spent approximately $1.3 million of the $1.4 million estimate. Currently PNR believes all major abandonment charges have been incurred. On December 18, 2008, PNR informed the Trustee that there is no longer a deficit balance due for abandonment accrual for amounts expended and for projected future abandonment expenses for the properties in which the Trust has an interest.

Liquidity and Capital Resources

        In accordance with the provisions of the Trust conveyance, generally all revenues received by the Trust, net of Trust administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the unitholders. Based on the current general and administrative expenditures being incurred in connection with the litigation and the absence of Royalty income, the Trustee was required to borrow money in accordance with the Trust Indenture to fund Trust expenses. On September 28, 2007 the Trust entered into a Demand Promissory Note agreement with JPMorgan in order to cover portions of its operating expenses. The lender approved an uncommitted line of credit to the Trust in a principal amount not to exceed $3 million. As part of that agreement, JPMorgan pays the expenses on behalf of the Trust. JPMorgan may decline to fund any request of the Trust for borrowings at anytime, for any reason, including the event that JPMorgan has reason to believe that the Trust will not be able to satisfy its obligation to repay the Demand Loans. Interest on the note is calculated at a rate per annum equal to Prime Rate plus two percent (2%), paid annually. The Demand Promissory Note is secured by a pledge of the Trust Estate, as that term is defined in the Trust Indenture, including without limitation the 99.99% general partnership interest in the Mesa Offshore Royalty Partnership owned by the Trust, pursuant to a Pledge Agreement dated September 29, 2007, as amended by the First Amendment to Pledge Agreement dated as of December 3, 2007, executed by the Trust for the benefit of the Lender. The Trust may borrow amounts under this Note until such time as JPMorgan makes demand for payment in full or December 31, 2008, whichever is earlier. On December 3, 2007, JPMorgan, individually and as lender, entered into an Amended and Restated Promissory Note, with the Trust as borrower, to amend the

34

Demand Promissory Note to provide for, among other provisions, an extension of the stated maturity date of the Loans made pursuant to the Demand Promissory Note and the Amended and Restated Note until the earlier of (1) December 31, 2009, (2) 31 days after the Trust's receipt of any settlement proceeds, recovery or judgment in connection with the Lawsuit, (3) final liquidation of the Trust's assets, or (4) the Settlement Agreement is not approved by the Court. Additionally, the amendment provided that the Trust may continue to obtain loans under the note until the maturity date, as long as, the amount borrowed does not exceed $3 million and the loan is not in default. The amendment also provided that interest expense shall be due and payable on the maturity date. On August 25, 2008, the Trustee executed an amended and restated Demand Note that among other things increased the aggregate principal amount available for borrowing to $4 million and amended the definition of "Maturity Date" to delete the text relating to the failure of the Court to approve the prior Settlement Agreement in the Lawsuit. As of December 31, 2008, there was outstanding $3,557,646 of principal advanced for payment of Trust expenses together with $230,440 of accrued and unpaid interest expense. At December 31, 2008, the Trust had $442,354 available under this facility. Should the Trust fully utilize the funds available under the Demand Promissory Note, the Trustee will attempt to borrow additional money. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at all. The Trust Indenture prohibits the Trustee from making any distributions to unitholders until these loans are repaid in full.

        On January 28, 2009, the Trustee executed and delivered to JPMorgan a Third Amended and Restated Promissory Note, dated as of January 12, 2009, increasing the principal amount available for borrowing, subject to the terms of such note, to $5 million.

        The Trust's source of cash is the Royalty income received from the Partnership's share of the net proceeds from the Royalty Properties. Reference is made to Note 8 in the Notes to Financial Statements under Item 8 of this Form 10-K for estimates of future Royalty income attributable to the Partnership, of which the Trust has a 99.99% interest.

Production and Price Review

        Production volumes for natural gas increased to 79,877 Mcf in 2008 as compared with 4,198 Mcf in 2007. The average sales price received for natural gas in 2008 was $8.86 per Mcf as compared with $6.79 per Mcf in 2007. Crude oil, condensate and natural gas liquids production volumes increased to 6,138 barrels in 2008 as compared to 19 barrels in 2007. The average sales price in 2008 for crude oil, condensate and natural gas liquids was $101 per barrel as compared with $53.84 per barrel in 2007.

        Production volumes for natural gas decreased to 4,198 Mcf in 2007 as compared with 28,517 Mcf in 2006. The average sales price received for natural gas in 2007 was $6.79 per Mcf as compared with $7.65 per Mcf in 2006. Crude oil, condensate and natural gas liquids production volumes decreased to 19 barrels in 2007 as compared to 359 barrels in 2006. The average sales price in 2007 for crude oil, condensate and natural gas liquids was $53.84 per barrel as compared with $58.64 per barrel in 2006.

Off-Balance Sheet Arrangements

        None.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk.

        Not applicable.

35

Item 8.    Financial Statements and Supplementary Data.

MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME

	Years Ended December 31,
	2008		2007			2006
Royalty income	$	—	$	—		$	145,642
Interest income		—		5,080			29,293
General and administrative expenses		—		(5,080	)		(174,935	)
Distributable income	$	—	$	—		$	—
Distributable income per unit	$	—	$	—		$	—

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	December 31,
	2008			2007
ASSETS
Cash and short-term investments	$	69		$	2,969
Net overriding royalty interest in oil and gas properties		380,905,000			380,905,000
Less: accumulated amortization		(380,902,063	)		(380,902,063	)
Total assets	$	3,006		$	5,906
LIABILITIES AND TRUST CORPUS
Reserve for trust expense	$	69		$	2,969
Trust expense payable		270,595			190,955
Interest payable		230,440			31,187
Note payable—JPMorgan		3,557,646			1,673,617
Trust Corpus (71,980,216 units of beneficial of interest authorized and outstanding)		(4,055,744	)		(1,892,822	)
Total liabilities and trust corpus	$	3,006		$	5,906

STATEMENTS OF CHANGES IN TRUST CORPUS

	Years Ended December 31,
	2008			2007			2006
Trust corpus, beginning of year	$	(1,892,822	)	$	2,937		$	3,048
Trust expenses payable		(79,640	)		(190,955	)		—
Interest payable		(199,253	)		(31,187	)		—
Note payable—JPMorgan		(1,884,029	)		(1,673,617	)		—
Amortization of net overriding royalty interest		—			—			(111	)
Trust corpus, end of year	$	(4,055,744	)	$	(1,892,822	)	$	2,937

The accompanying notes are an integral part of these financial statements.

36

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS

(1) Trust Organization and Provisions

The Trust

        The Mesa Offshore Trust (the "Trust") was created effective December 1, 1982. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership, which was predecessor to MESA Inc., transferred to the Trust a 99.99% interest in the Mesa Offshore Royalty Partnership (the "Partnership"). The Trust is an independent trust administered by 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 Bank National Association. JPMorgan Chase & Co. and The Bank of New York Company ("BNY") announced in April 2006 an agreement pursuant to which BNY would acquire a portion of JPMorgan Chase & Co.'s corporate trust business in exchange for BNY's consumer small business and middle market banking business. This transaction did not include any transfer by JPMorgan of its obligations as Trustee of this Trust.

        The terms of the Mesa Offshore Trust Indenture (the "Trust Indenture") provide, among other things, that:

        (a)   the Trust cannot engage in any business or investment activity or purchase any assets;

        (b)   the interest in the Partnership can be sold in part or in total for cash upon approval of the unitholders;

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

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

        (e)   the Trust will terminate upon the first to occur of the following events: (i) the total amount of cash received per year by the Trust for each of three successive years commencing after December 31, 1987 is less than ten times one-third of the total amount payable to the Trustee as compensation for such three-year period (the "Termination Threshold") or (ii) a vote by holders of a majority of the outstanding units in favor of termination. Amounts earned by the Trustee as compensation were approximately $181,000, $177,000 and $360,000 for the years 2008, 2007 and 2006, respectively. As described further in "Legal Proceedings and Status of the Trust" below, the Termination Threshold was met in the three consecutive years ending December 31, 2004. However, due to pending litigation involving the Trust that directly challenges whether the Termination Threshold has in fact been met, the Trustee cannot predict the timing of the sale of all or a portion of the Partnership assets as part of the Trust liquidation and termination. As part of the liquidation and eventual termination of the Trust, the Trustee will sell for cash all the assets held by the Partnership and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied.

The Partnership

        The Partnership was created to receive and hold a net overriding royalty interest (the "Royalty") in ten producing and non-producing oil and gas properties located in federal waters offshore Louisiana and Texas (the "Royalty Properties"). MESA Inc. created the Royalty out of its working interest in the Royalty Properties and transferred it to the Partnership. Until August 7, 1997, MESA Inc. owned and operated its assets through Mesa Operating Co. ("Mesa"), the operator and the managing general

37

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(1) Trust Organization and Provisions (Continued)

partner of the Royalty Properties. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("PNRC"), formerly a wholly owned subsidiary of MESA, Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. ("PNR") (successor to Mesa), a wholly owned subsidiary of PNRC (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, PNR owns and operates its assets through PNRC and is also the managing general partner of the Partnership.

        The Partnership is owned 99.99% by the Trust and 0.01% by PNR. PNR serves as the managing general partner of the Partnership. PNR receives no compensation for serving as managing general partner other than the income it receives attributable to its interest in the Partnership.

Legal Proceedings and Status of the Trust

        The Trust Indenture provides that the Trust will liquidate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of insufficient production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture. The Trustee has previously taken steps to begin the process of liquidating the Trust; however, the legal proceedings described herein directly challenge whether the Termination Threshold has in fact been met and thus have affected the liquidation process. See "Business—Timing of Liquidation." The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no control over the occurrence of the Termination Threshold or its consequences.

        The Trust Indenture provides the Trustee a two-year period during which it must sell all of the assets of the Partnership; however, the legal proceedings described herein directly challenge whether the Termination Threshold has in fact been met and thus affected the liquidation process, such that the Trustee initially delayed the sale of the Partnership's oil and gas assets in efforts to investigate and resolve the claims. Now, due to the continuation of the litigation into its fourth year, the related cost to the Trust, and the opportunity to realize greater proceeds for the benefit of the Trust estate, the Trustee concluded that a public auction of the Partnership's oil and gas assets was in the best interest of the Trust at this time, and the Court allowed a public auction of these assets to go forward yet, at the public auction on March 18, 2009, no bids were submitted, so the Trustee is considering its options under the Trust Indenture and in light of the pending litigation. Due to the pending litigation, the Trustee can not predict the timing of the sale of the assets. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee expects that any future sale process will be open to any persons desiring to participate, but, as is customary, access to information and participation may be limited to persons who execute confidentiality agreements regarding information provided by the working interest owners. The Trustee may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a "public" auction in the sense that it may not be open to anyone who does not satisfy these requirements.

        On April 11, 2005, MOSH Holding, L.P. ("MOSH") filed an Original Petition in the District Court of Travis County, Texas, 250th Judicial District, against PNRC; PNR; Woodside Energy (USA), Inc. ("Woodside"); and JPMorgan, as Trustee of the Mesa Offshore Trust (Case No. GN501113) (the "Lawsuit"). The Lawsuit is currently before the 334th Judicial District of Harris Country, Texas (the

38

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(1) Trust Organization and Provisions (Continued)

"Court"). MOSH's Original Petition alleged Pioneer and Woodside are liable for various actions, including (1) a wrongful farmout by Pioneer to Woodside of the Brazos A-39 Lease, (2) a wrongful delay by Pioneer in producing the Brazos A-39 Lease and the Midway #5 well drilled thereon, (3) fraudulent accounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aiding and abetting breach of fiduciary duty by Woodside, (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, MOSH later added claims against the Trustee for (1) an accounting, and (2) breach of fiduciary duty. The remedies MOSH seeks include (a) reconstruing the Trust Indenture to determine that the Trust is not terminated because there has or should have been production that would have generated revenues to extend the life of the Trust, (b) requiring the Trustee to pursue certain claims, or to allow MOSH to pursue such claims, (c) setting aside any farmouts by Pioneer in which there have been conveyances to an alleged affiliate of Pioneer, (d) the removal of JPMorgan as Trustee, (e) the return or forfeiture of compensation to JPMorgan, (f) monetary damages against Pioneer, Woodside and JPMorgan, and (g) unspecified exemplary damages against all defendants.

        MOSH's Original Petition did not contain any claims against the Trustee, except to enjoin the Trustee from terminating the Trust during the pendency of the Lawsuit. In April 2005, the Trustee entered into an agreement with MOSH whereby the Trustee would not sell the Trust assets without first giving MOSH 60-days written notice. This agreement allowed MOSH time to obtain documents and discovery from Pioneer and Woodside, and allowed the Trustee time to investigate the claims asserted by MOSH against Pioneer and Woodside to determine if they had any merit and, most importantly, whether the claims would benefit the Trust. During the six month period between April and October 2005, the Trustee conducted an independent investigation including: numerous meetings and discussions with the parties; reviewing the relevant documents with the Trustee's counsel; employing independent reservoir engineers to evaluate the reserves in which the Trust has an interest; engaging independent joint venture auditors to examine the accounting records of the operator, Pioneer, relating to revenues and expenses allocated to the Partnership's interests; and obtaining from both MOSH and Pioneer their respective legal analyses of the challenged farmout.

        Throughout 2005, the parties also anticipated that the Midway #5 well on the Brazos A-39 Lease that is the primary subject of the Lawsuit would go into production. Given the vast discrepancy between the reserves claimed by MOSH and those projected by Pioneer for the Midway #5 well, actual production results would significantly impact the Trustee's assessment of whether the Trust was better off with the cost-free override created by the Pioneer-Woodside farmout, or the prior cost-burdened net profits interest that MOSH seeks to restore through the Lawsuit. Unfortunately, Hurricane Katrina struck the Gulf of Mexico in August 2005 and delayed the commencement of production until 2006.

        Faced with this post-Katrina situation in the fall of 2005, the Trustee urged all the parties to consent to a bifurcated trial of the farmout issue on an expedited basis. The Trustee proposed to MOSH that if the Court determined that the farmout was not valid and that restoring the net profits interest would benefit the Trust, then the Trust would reimburse MOSH's reasonable attorneys' fees, up to $100,000, and the Trustee would allow MOSH's counsel to represent the Trust in prosecuting the damages portion of the case. Conversely, if MOSH were to lose on the expedited determination of the farmout issue, and in the absence of more evidence to support any ancillary claims, then MOSH would dismiss the other claims and would not be reimbursed, and the Trustee would move forward to terminate the Trust.

39

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NOTES TO FINANCIAL STATEMENTS (Continued)

(1) Trust Organization and Provisions (Continued)

        Although the Trustee, Pioneer, and Woodside all agreed to an expedited trial of the farmout issues, MOSH balked. Contrary to the assertions of MOSH and the Intervenor Plaintiffs, the Trustee never agreed that the claims asserted by MOSH against Pioneer and Woodside "had merit"—the Trustee simply stated that the farmout issue might merit immediate adjudication at that time to determine if MOSH was legally correct.

        When MOSH refused to agree to an expedited and bifurcated trial as proposed by the Trustee, the Trustee informed MOSH that the Trustee's investigation of MOSH's allegations beyond the farmout issues failed to convince the Trustee that pursuing those claims and incurring the related legal fees and expenses would benefit the Trust. Moreover, the Trustee informed MOSH that the Trustee's independent joint venture auditors and reservoir engineers had not found any evidence to date to support any of MOSH's damage allegations. Therefore, the Trustee informed MOSH that the Trustee's investigation indicated that the Trust was better off with the post-farmout cost-free overriding royalty interest than the pre-farmout cost-burdened net profits interest, so the funding of MOSH's efforts to set aside the farmout with Trust funds would not be in the best interest of the Trust.

        It was at this point, in November 2005, in the midst of the Trustee's negotiations with MOSH to obtain an agreed resolution of MOSH's claims, that MOSH alleged for the first time that the Trustee had a conflict of interest because of JPMorgan's long-standing lending relationship with Pioneer. Although it is clear under the Trust Indenture, the Texas Trust Act, and relevant case law that JPMorgan is not precluded, by holding the position of Trustee, from pursuing commercial banking activities not involving Trust funds, MOSH amended its petition and asserted claims against the Trustee on November 28, 2005.

        Although it responded that MOSH's claims against the Trustee were meritless, to avoid any further assertion that the Trustee could not impartially evaluate MOSH's claims, on November 30, 2005, JPMorgan announced 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, the Court denied MOSH's motion for a temporary injunction to remove JPMorgan as Trustee and appoint a principal of MOSH, Timothy Roberson, as a temporary Trustee. At the Court's suggestion, JPMorgan agreed to continue as Trustee, until such time as a substitute trustee was found that fulfilled the qualifications of Trustee stated in the Trust Indenture. Since that hearing, none of the parties have identified a willing qualified successor Trustee that is not also a lender under one of Pioneer's credit facilities (which status MOSH 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 MOSH. Another group of unitholders, led by Keith A. Wiegand, (together with Dagger-Spine, the "Intervenors") also filed on March 9, 2007 a petition to intervene as plaintiffs in the Lawsuit, incorporating and adopting the same claims asserted by MOSH. MOSH and the Intervenors are referred to hereinafter as the "Plaintiffs."

        In 2006, after the Court denied MOSH's attempt to remove JPMorgan as Trustee, the parties pursued formal discovery in the Lawsuit. During this period, the Trustee continued to evaluate the merits of the alleged claims against Pioneer and Woodside. A central allegation by MOSH and the Intervenors is that Pioneer and Woodside delayed the commencement of production from the well drilled pursuant to the Pioneer-Woodside farmout—the Midway #5 well on the Brazos A-39 Lease. However, Woodside and Pioneer witnesses gave sworn testimony in depositions about the commercial

40

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NOTES TO FINANCIAL STATEMENTS (Continued)

(1) Trust Organization and Provisions (Continued)

and technical reasons for the delays in bringing the well on line. The well commenced production in April 2006. After production began, the Trustee instructed its independent petroleum reserve engineers to evaluate how the production results and projected future production from the well might affect the value of the Trust's interests. The Trustee's independent engineers determined that the initial production data from the well did not warrant a material change in prior assessments of the value of the Trust's assets.

        Pioneer subsequently reported to the Trustee that production from the well was suspended in July 2006 due to mercury contamination identified at downstream facilities where the production from the well is commingled with production from other wells. An updated evaluation from the Trustee's independent petroleum reserve engineers estimated that revenues from future production likely would not exceed the costs of drilling and completing the well. This confirmed that, if the Partnership's interest in the underlying lease had remained, or was, a cost-burdened net profits interest, instead of the cost-free overriding royalty interest the Partnership held as a result of the Pioneer-Woodside Farmout, the Partnership would not have received, or would not receive, any payments from this production, and the Trust accordingly would not have received any associated distributions. Further, the production data did not support reserves of the size asserted by the Plaintiffs. The well resumed production in February 2007, but the well was shut in again on April 18, 2007 due to an increase in hydrogen sulfide content coincidental with an increase in water production. Pioneer implemented a hydrogen sulfide contingency plan, which was required and approved by the Mineral Management Service ("MMS"), including the installation of the necessary alarm and safety systems. The well was shut in October 4, 2008 after discovery of corrosion in the production separator on the host platform. A replacement production separator was installed on the host platform. The well was returned to production on March 19, 2009.

        Given its conclusion that the Trust was better off with the post-farmout override, and hoping to the end this expensive litigation and liquidate the Trust per the Trust Indenture, the Trustee reached a conditional settlement on January 26, 2007 with Pioneer and Woodside of the claims asserted by the Plaintiffs against Pioneer and Woodside. The conditional settlement was set forth in the Mutual Release and Settlement Agreement dated as of January 26, 2007 (the "Pioneer/Woodside Settlement Agreement"). The Trustee filed a motion for approval of the Pioneer/Woodside Settlement Agreement with the Court on January 30, 2007. The Trustee believed that the Pioneer/Woodside Settlement Agreement was in the best interest of the unitholders, but the Plaintiffs opposed it, and on June 19, 2007, the Court issued an Order denying the Trustee's motion to approve the Pioneer/Woodside Settlement Agreement.

        In June and July 2007, Pioneer and Woodside filed motions with the Court that argued that the claims against them did not have merit as a matter of law. Pioneer's motion included an argument that the Plaintiffs do not have the legal right to sue Pioneer because the claims belong to the Trust, not the beneficiaries of the Trust. On October 19, 2007, the Trustee offered to assign to the Plaintiffs the Trust's claims against Pioneer and Woodside, but the plaintiffs rejected that offer. Through their counsel, the Plaintiffs and the Trustee also began negotiating a resolution of the claims pending between them, and on October 26, 2007, the Trustee and the Plaintiffs informed the Court of an agreement in principle to settle.

        On December 3, 2007, the Trustee entered into a Settlement Agreement and Release with the Plaintiffs and additional Trust unitholders (the "Plaintiffs' Settlement Agreement"). Also on December 3, 2007, the Trustee and the Plaintiffs filed a Joint Motion for Approval of Settlement

41

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(1) Trust Organization and Provisions (Continued)

Agreement (the "Joint Motion"). In response to the Joint Motion, on December 21, 2007, Pioneer filed cross-claims against the Trustee seeking declaratory and injunctive relief to prevent certain aspects of the proposed settlement between the Trustee and the Plaintiffs. On January 14, 2008, the Trustee filed an answer to Pioneer's cross-claims, in which the Trustee denied the cross-claims in their entirety, stated that they were baseless, and set forth numerous affirmative defenses. On January 22, 2008, the Court issued an Order denying the Joint Motion. As a result, the conditions precedent to the Plaintiffs' Settlement Agreement could not be satisfied, and the Plaintiffs' Settlement Agreement became null and void. In addition to denying the Joint Motion, the Court also considered and denied in the same Order (i) the application by the Plaintiffs for the appointment of a temporary trustee and (ii) Pioneer's application for a temporary restraining order. As a result of the Court's denial of the Joint Motion, and the Court's denial of the Plaintiffs' application for the appointment of a temporary trustee, JPMorgan elected not to resign in order to avoid a vacancy, and continues to serve as Trustee. The Trustee continues to desire the appointment of a successor Trustee.

        On April 28, 2008, the Court issued a Docket Control Order, setting the trial date for December 8, 2008. On July 3, 2008, the Plaintiffs filed a Third Amended Petition, seeking, among other things, to add claims against the Partnership (though its partners Pioneer and the Trustee) and JPMorgan in an individual capacity. By order dated July 3, 2008, the Court denied Pioneer's pending motions for summary judgment, including Pioneer's challenge to Plaintiffs' standing. Pioneer then filed a petition for writ of mandamus to the Houston Fourteenth Court of Appeals on July 22, 2008, seeking to reverse the trial courts' ruling on standing. On September 25, 2008, the Houston Fourteenth Court of Appeals denied Pioneer's petition for writ of mandamus, and Pioneer filed a petition for writ of mandamus with the Supreme Court of Texas on October 1, 2008. On October 24, 2008, the group of unitholders led by Keith A. Wiegand filed a Motion for Non-Suit Without Prejudice, and the Court granted the motion on October 24, 2008. Thus, all references herein to "Plaintiffs" after the date of October 24, 2008 include only MOSH and Dagger-Spine. At a hearing before the Court on October 31, 2008, the Plaintiffs agreed to postpone the trial again, and the trial is now scheduled for April 13, 2009. The Supreme Court of Texas denied Pioneer's petition for writ of mandamus on November 21, 2008.

        By notice dated February 6, 2009, which the Trustee mailed to all unitholders of record on February 10, 2009, the Trustee announced that the Termination Threshold had been met and that, as a result, it had instructed Pioneer to sell the oil and gas assets of the Partnership at public auction on March 18, 2009. In addition, the Trustee announced that the sale would include all of Pioneer's interests in Brazos Block A-39. On March 3, 9, and 12, respectively, unitholders Gordon Stamper, Robert Miles, and Keith Wiegand—formerly part of the group of Intervenors led by Keith Wiegand (collectively, the "Individual Intervenors")—filed pro se motions with the Court, requesting to intervene in the Lawsuit. At the public auction on March 18, 2009, no bids were submitted, so the Trustee is considering its options under the Trust Indenture and in light of the pending litigation. On March 25, 2009, Plaintiffs filed their Fourth Amended Original Petition, Application for Temporary Restraining Order, Temporary Injunction, Show Cause Order, and Permanent Injunction. As of the date of this report, the trial of the Lawsuit remains scheduled for April 13, 2009, but the Plaintiffs have filed a motion for continuance, and the Trustee anticipates that the trial will be reset.

        The Trustee will make the full detail of the underlying data of the December 31, 2008 reserve report available for use in connection with the sale of the Partnership's Royalty Properties as part of the Trust termination. For more information regarding the estimated remaining life of each of the Royalty Properties, the estimated future net revenues of the Royalty Properties and information

42

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(1) Trust Organization and Provisions (Continued)

relating to farm-outs of interests on the Royalty Properties, see Note 8 in the Notes to Financial Statements. The final distribution to unitholders will be an amount net of funds required to satisfy all Trust liabilities.

(2) Going Concern

        The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. The Trust Indenture provides that the Trust will liquidate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of insufficient production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003, and 2004 fell below the Termination Threshold prescribed by the Trust Indenture. In 2005, the Trustee began procedures to liquidate the Trust's assets. Once the Trustee has liquidated all of the Trust's assets and has met all its obligations as described in the Trust Indenture, the Trust will no longer be a viable entity. Due to the pending litigation, the Trustee cannot predict the timing of the sale of all or a portion of the assets of the Partnership as part of the Trust Termination.

        During the two years ended December 31, 2008, the Trust incurred general and administrative expenses which exceeded Royalty and interest income and its available cash reserves, due to the absence of royalty income and expenses incurred in connection with the ongoing litigation. As such, the Trustee was required to borrow money in accordance with the Trust Indenture to fund Trust expenses. The Trustee entered into a Demand Promissory Note with JPMorgan on September 28, 2007, which was amended on December 3, 2007, for demand loans that may be advanced from time to time in the principal amount of up to $3.0 million. The amendment provided for, among other provisions, an extension of the stated maturity date of the Loans made pursuant to the Demand Promissory Note and the Amended and Restated Note until the earlier of (1) December 31, 2009, (2) 31 days after the Trust's receipt of any settlement proceeds, recovery or judgment in connection with the Lawsuit, (3) final liquidation of the Trust's assets, or (4) the Settlement Agreement is not approved by the Court.

        On January 22, 2008, the court in which the lawsuit was pending issued an Order denying the Joint Motion for approval of the Settlement Agreement. According to the terms of the Amended Promissory Note, the note matured on this date as a result of the denial, and all portions of the outstanding principal under this note together with accrued and unpaid interest became due, in full. However, on August 25, 2008, in connection with the execution of the Second Amended and Restated Promissory Note, the definition of "Maturity Date" was amended to delete the test relating to the failure of the Court to approve the prior Settlement Agreement. As a result, the due date of the Demand Promissory Note was not accelerated as a result of the order described above, however, the maturity date remained (1) December 31, 2009, (2) 31 days after the Trust's receipt of settlement proceeds, recovery or judgment in connection with the Lawsuit or (3) final liquidation of the Trust's assets.

        On January 28, 2009, the Trustee executed and delivered to JPMorgan a Third Amended and Restated Promissory Note, dated as of January 12, 2009, increasing the principal amount available for borrowing, subject to the terms of such note, to $5 million. Should the Trust fully utilize the funds available under the Demand Promissory Note, the Trustee will attempt to borrow additional money. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable, or at all.

43

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(2) Going Concern (Continued)

        Currently, the Trust does not have the cash resources available to repay the debt. This raises substantial doubt regarding the Trust's ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

(3) Net Overriding Royalty Interest

        The instruments conveying the Royalty to the Partnership provide that PNR will calculate and pay to the Partnership each month 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 from sales of its share of oil and gas from the Royalty Properties (gross proceeds) over the operating and capital costs incurred. Costs exceeding gross proceeds for any month are recovered by PNR, with interest thereon at the prime rate of the Bank of America plus one-half percent, out of future gross proceeds prior to making further royalty payments to the Partnership.

        Amortization of the Royalty, which is calculated on the basis of current royalty income in relation to estimated future royalty income, is charged directly to trust corpus since such amounts do not affect distributable income.

(4) Basis of Accounting

        The financial statements of the Trust do not include any adjustment as a result of the termination of the Trust as described in notes 1 and 2 and are prepared on the following basis:

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

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

        (c)   Trust general and administrative expenses are recorded in the month they accrue and are recoupable from Royalty income. Trust expenses payable and the note payable at December 31, 2008 and 2007 are reported as a reduction in Trust Corpus.

        This basis for reporting distributable income is considered to be the most meaningful because distributions to the unitholders for a month are based on net cash receipts for such month. However, it will differ from the basis used for financial statements prepared in accordance with accounting principles generally accepted in the United States of America because, under such accounting principles, royalty income for a month would be based on net proceeds from sales for such month without regard to when calculated or received and interest income for a month would be calculated only through the end of such month, and accounting principles generally accepted in the United States may require a liquidation basis of accounting.

        The instruments conveying the Royalty provide that the working interest owner will calculate and pay the Partnership each month an amount equal to 90% of the net proceeds for the preceding month. Generally, net proceeds means the excess of the amounts received by the working interest owner from sales of oil and gas from the Royalty Properties plus other cash receipts over operating and capital

44

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(4) Basis of Accounting (Continued)

costs incurred. As of December 31, 2007, there was a deficit balance due PNR of approximately $1.5 million which as been deducted from gross proceeds on the Royalty properties, which reduced Royalty income. Currently, PNR believes all major abandonment charges have been incurred. On December 18, 2008, PNR informed the Trustee that there is no longer a deficit balance due for abandonment accrual for amounts expended and for projected future abandonment expenses for the properties in which the Trust has an interest.

        No Royalty income will be distributed to unitholders until the Trustee recoups Trust expenses being paid from the reserve that the Trustee has established for anticipated future general and administrative expenses and any loans secured by the Trustee to pay Trust expenses are repaid in full. As of December 31, 2008, $4,058,681 will be recouped by the Trustee from future Royalty income before Trust distributions will resume. During the twelve months ended December 31, 2008, no royalty income or proceeds from the sale of the properties was received by the Trust; accordingly no Trust distribution was made to the unitholders.

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

	Years Ended December 31,
	2008			2007			2006
General and administrative costs incurred during the year	$	1,966,572		$	2,666,727		$	1,223,271
Expenses paid by JPMorgan for prior period		190,955			—			—
(Deductions from) additions to reserve for trust expenses		(2,900	)		(797,075	)		(1,048,336	)
Total expenses paid by JP Morgan during current period		(1,884,032	)		(1,673,617	)		—
Unpaid trust expenses		(270,595	)		(190,955	)		—
General and administrative costs as reported	$	—		$	5,080		$	174,935

(5) JPMorgan Demand Promissory Note

        On September 28, 2007, the Trust entered into a Demand Promissory Note agreement with JPMorgan in order to cover portions of its operating expenses. The lender approved an uncommitted line of credit to the Trust in a principal amount not to exceed $3 million. As part of the agreement, JPMorgan pays the expenses on behalf of the Trust. JPMorgan may decline to fund any request of the Trust for borrowings at anytime, for any reason, including the event that JPMorgan has reason to believe that the Trust will not be able to satisfy its obligation to repay the Demand Loans. Interest on the note is calculated at a rate per annum equal to Prime Rate plus two percent (2%), paid annually. The Demand Promissory Note is secured by a pledge of the Trust Estate, as that term is defined in the Trust Indenture, including without limitation the 99.99% general partnership interest in the Mesa Offshore Royalty Partnership owned by the Trust, pursuant to a Pledge Agreement dated September 29, 2007, as amended by the First Amendment to Pledge Agreement dated as of December 3, 2007, executed by the Trust for the benefit of the Lender. The Trust may borrow amounts

45

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(5) JPMorgan Demand Promissory Note (Continued)

under this Note until such time as JPMorgan makes demand for payment in full or December 31, 2008, whichever is earlier.

        On December 3, 2007, JPMorgan Chase Bank, N.A., individually and as lender, entered into an Amended and Restated Promissory Note, with the Trust as borrower, to amend the Demand Promissory Note to provide for, among other provisions, an extension of the stated maturity date of the Loans made pursuant to the Demand Promissory Note and the Amended and Restated Note until the earlier of (1) December 31, 2009, (2) 31 days after the Trust's receipt of any settlement proceeds, recovery or judgment in connection with the Lawsuit, (3) final liquidation of the Trust's assets, or (4) the Settlement Agreement is not approved by the Court. Additionally, the amendment provided that the Trust may continue to obtain loans under the note until the maturity date, as long as the amount borrowed does not exceed $3 million and the loan is not in default. The amendment also provided that interest expense shall be due and payable on the maturity date.

        On August 25, 2008, the Trustee executed an amended and restated Demand Note that among other things increased the aggregate principal amount available for borrowing to $4.0 million and amended the definition of "Maturity Date" to delete the text relating to the failure of the Court to approve the prior Settlement Agreement.

        On January 28, 2009, the Trustee executed and delivered to the lender a Third Amended and Restated Promissory Note, dated as of January 12, 2009, increasing the principal amount available for borrowing, subject to the terms of such note, to $5 million. On January 28, 2009, the Trust and JPMorgan Chase Bank, N.A. also entered into a Third Amendment to Pledge Agreement, dated as of January 12, 2009, amending the definition of "Collateral" from the Second Amendment to the Pledge Agreement dated June 25, 2008 to include (1) all issued and outstanding general partnership interests by the Trust in the Partnership, together with any cash or property received in exchange or in substitution for such interests (collectively, the "Pledged Assets"), and any distributions received on such Pledged Assets or cash or property received upon any conversion or in exchange for such Pledged Assets; (2) all Additional Collateral (as defined therein) owned by the Trust; (3) all deposit accounts in the name of the Trust; (4) any consideration received or due to the Trust; and (5) all proceeds of any and all of the foregoing.

        Interest is payable at a base rate offered by JPMorgan as announced publicly at its principal office as its prime commercial lending rate, plus 2%. The rate effective as of December 31, 2008 was a Prime Rate of 3.25%, plus 2% for a combined rate of 5.25%.

        As of December 31, 2008, there was outstanding $3,557,646 of principal advanced for payment of Trust expenses together with $230,440 of accrued and unpaid interest expense. At December 31, 2008, the Trust had $442,354 available under this facility. Should the Trust fully utilize the funds available under the Demand Promissory Note, the Trustee will attempt to borrow additional money. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at all.

(6) Distributions to Unitholders

        Under the terms of the Trust Indenture, the Trustee must distribute to the unitholders all cash receipts, after paying liabilities and providing for cash reserves as determined necessary by the Trustee. The amounts distributed are determined on a monthly basis and are payable to unitholders of record as of the last business day of each month. However, cash distributions are made quarterly in January,

46

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(6) Distributions to Unitholders (Continued)

April, July and October, and include interest earned from the monthly record dates to the dates of distribution.

(7) Federal Income Taxes

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

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

(8) Supplemental Reserve Information (Unaudited)

        Estimates of the proved oil and gas reserves attributable to the Royalty as of December 31, 2008, 2007 and 2006, are based on a report prepared by DeGolyer and MacNaughton ("D&M"), independent petroleum engineering consultants. The estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission (the "SEC") and the Financial Accounting Standards Board. Accordingly, the estimates were based on existing economic and operating conditions. The reserve volumes and revenue values contained in the reserve report for the Partnership interest were estimated by allocating to the Partnership a portion of the estimated combined net reserve volumes of the Royalty Properties based on future net revenue. Production volumes are allocated based on royalty income. Because the net reserve volumes attributable to the Partnership interest are estimated using an allocation of reserve volumes based on estimates of future net revenue, a change in prices or costs will result in changes in the estimated net reserve volumes. Therefore, the estimated net reserve volumes attributable to the Partnership interest will vary if different future price and cost assumptions are used. Only costs necessary to develop and produce existing proved reserve volumes were assumed in the allocation of reserve volumes to the Royalty.

        Future prices for natural gas were based on prices in effect as of each year end and existing contract terms. Prices being received as of each year end were used for sales of oil, condensate and natural gas liquids. Operating costs, production and ad valorem taxes and future development and abandonment costs were based on current costs as of each year end, with no escalation.

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

        Estimates of reserve volumes attributable to the Royalty are shown in order to comply with requirements of the SEC. There is no precise method of allocating estimates of physical quantities of

47

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(8) Supplemental Reserve Information (Unaudited) (Continued)

reserve volumes between PNR and the Partnership, since the Royalty is not a working interest and the Partnership does not own and is not entitled to receive any specific volume of reserves from the Royalty. The quantities of reserves attributable to the Partnership have been and will be affected by changes in various economic factors utilized in estimating net revenues from the Royalty Properties, as well as any exploration activities which may be conducted by PNR. Therefore, the estimates of reserve volumes set forth below are to a large extent hypothetical and differ in significant respects from estimates of reserves attributable to a working interest.

        The future net revenues contained in the previously mentioned reserve report have not been reduced for future general and administrative expenses of the Trust, which are expected to approximate $2,500,000 annually. The general and administrative expenses of the Trust may increase for the remaining duration of the Trust, depending on the amount of royalty income, increases in accounting, engineering, legal, and other professional fees and other factors.

        The following schedules set forth (i) the estimated net quantities of proved and proved developed oil, condensate and natural gas liquids and natural gas reserves attributable to the Royalty, and (ii) the standardized measure of the discounted future royalty income attributable to the Royalty and the nature of changes in such standardized measure between years. These schedules are prepared on the accrual basis, which is the basis on which PNR maintains its production records and is different from the basis on which the Royalty is computed.

Estimated Quantities of Proved and Proved Developed Reserves (Unaudited)

			Oil and Condensate			Natural Gas
			(Bbls)			(Mcf)
Proved Reserves:
	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
	Revisions of previous estimates			(203	)		(79,006	)
	Extensions, discoveries and other additions			—			—
	Production			(19	)		(4,198	)
	December 31, 2007			10,391			276,858
	Revisions of previous estimates			1,829			16,318
	Extensions, discoveries and other additions			—			—
	Production			(6,138	)		(79,877	)
		December 31, 2008		6,082			213,299
Proved Developed Reserves:
	December 31, 2005			10,766			460,055
	December 31, 2006			10,613			360,062
	December 31, 2007			10,391			276,858
	December 31, 2008			6,082			213,299

(See Notes on following page.)

48

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(8) Supplemental Reserve Information (Unaudited) (Continued)

Standardized Measure of Future Royalty Income from
Proved Oil and Condensate and Gas Reserves, Discounted at 10% Per Annum (Unaudited)

		December 31,
		2008			2007			2006
		(In thousands)
Ninety percent of future gross proceeds		$	1,494		$	2,900		$	2,588
Less ninety percent of—
	Future operating costs		—			—			—
	Future capital costs, net of amounts previously accrued		—			(1,411	)		(1,411	)
	Deficit due PNR		—			(65	)		—
Future Royalty income			1,494			1,424			1,177
Discount at 10% per annum			(242	)		(232	)		(409	)
Standardized measure of future Royalty income from proved oil and gas reserves		$	1,252		$	1,192		$	768

Changes in the Standardized Measure of Future Royalty Income from
Proved Oil and Gas Reserves, Discounted at 10% Per Annum (Unaudited)

	Years Ended December 31,
	2008			2007			2006
	(In thousands)
Standardized measure at beginning of year	$	1,192		$	768		$	3,822
Revisions of previous estimates		114			(323	)		(861	)
Net changes in prices and production costs		(173	)		654			(1,141	)
Extensions, discoveries and other additions		—			—			—
Changes in estimated future development costs		—			16			(1,288	)
Royalty income		—			—			(146	)
Accretion of discount		119			77			382
Net changes in standardized measure		59			424			(3,054	)
Standardized measure at end of year	$	1,252		$	1,192		$	768

*

The estimated quantities of proved reserves, standardized measure of future Royalty income and changes in the standardized measure represent 100% of amounts for the Partnership in which the Trust has a 99.99% interest.

49

MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(8) Supplemental Reserve Information (Unaudited) (Continued)

Recent SEC Rule-Making Activity

        In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:

•

commodity prices—economic producibility of reserves and discounted cash flows will be based on a 12-month average commodity price unless contractual arrangements designate the price to be used;

•

disclosure of unproved reserves—probable and possible reserves may be disclosed separately on a voluntary basis;

•

proved undeveloped reserve guidelines—reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered;

•

reserve estimation using new technologies—reserves may be estimated through the use of reliable technology in addition to flow tests and production history; and

•

non-traditional resources—the definition of oil and gas producing activities will expand and focus on the marketable product rather than the method of extraction.

The rules are effective for fiscal years ending on or after December 31, 2009, and early adoption is not permitted. The Trust is currently evaluating the new rules and assessing the impact they will have on its reported oil and gas reserves. The SEC is coordinating with FASB to obtain the revisions necessary to SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," and SFAS No. 69, "Disclosures about Oil and Gas Producing Activities" to provide consistency with the new rules. In the event that consistency is not achieved in time for companies to comply with the new rules, the SEC will consider delaying the compliance date.

(9) Selected Quarterly Financial Data (Unaudited)

	Summarized Quarterly Results
	Three Months Ended
	March 31		June 30		September 30		December 31
2008:
Royalty income	$	—	$	—	$	—	$	—
Distributable income	$	—	$	—	$	—	$	—
Distributable income per unit	$	—	$	—	$	—	$	—
2007:
Royalty income	$	—	$	—	$	—	$	—
Distributable income	$	—	$	—	$	—	$	—
Distributable income per unit	$	—	$	—	$	—	$	—

50

REPORT OF INDEPENDENT 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 (the Trust) as of December 31, 2008 and 2007, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2008. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.

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

        These financial statements were prepared on the basis of accounting described in Note 4 to the financial statements, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of Mesa Offshore Trust as of December 31, 2008 and 2007, and the distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2008, in conformity with the basis of accounting described in Note 4 to the financial statements.

        The accompanying financial statements have been prepared assuming that Mesa Offshore Trust will continue as a going concern. As discussed in Note 1 to the financial statements, as a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust during 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture, resulting in the contractual termination of the Trust effective after December 31, 2004. In 2005, the Trustee began procedures to liquidate the Trust assets. In addition, as discussed in Note 2 to the financial statements, the Trust's current general and administrative expenses are in excess of Royalty Income received. This resulted in the Trust borrowing under a Demand Promissory Note which is due, prior to January 1, 2010. Accordingly, there exists substantial doubt about the Trust's ability to continue as a going concern. The Trustee's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

KPMG LLP

Houston, Texas
March 31, 2009

52

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

        None.

Item 9A.    Controls and Procedures

        Evaluation of Disclosure Controls and Procedures.    The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by PNR, as the managing general partner of the Partnership, and the working interest owners to JPMorgan, as Trustee of the Trust, and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

        As of the end of the period covered by this report, the trust officer acting on behalf of the Trustee responsible for the administration of the Trust conducted an evaluation of the Trust's disclosure controls and procedures. The officer acting on behalf of the Trustee concluded that the Trust's disclosure controls and procedures are effective.

        Due to the contractual arrangements of (i) the Trust Indenture, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding information furnished by the working interest owners, the Trustee relies on: (A) information provided by the working interest owners, including (i) the status of litigation, (ii) historical operating data, plans for future operating and capital expenditures and reserve information, as well as (iii) information relating to projected production; (B) information provided by the managing general partner of the Partnership that is collected by the managing general partner from the working interest owners; and (C) conclusions regarding reserves by reserve engineers or other experts in good faith. See Item 1A. Risk Factors "—The unitholders and the Trustee have no control over the operation or development of the Royalty Properties and have little influence over operation or development" and "—The Trustee relies upon the working interest owners and managing general partner for information regarding the Royalty Properties" in this Form 10-K for a description of certain risks relating to these arrangements and reliance.

        Changes in Internal Control over Financial Reporting.    In connection with the evaluation by the Trustee of changes in internal control over financial reporting of the Trust that occurred during the Trust's last fiscal quarter, no change in the Trust's internal control over financial reporting was identified that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning, the internal control over financial reporting of the working interest owners or the managing general partner of the Partnership.

        Trustee's Report on Internal Control over Financial Reporting.    The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust's internal control over financial reporting ("internal control over financial reporting") based on the criteria established in "Internal Control-Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee's evaluation under the framework in "Internal Control-Integrated Framework," the Trustee concluded that the Trust's internal control over financial reporting was effective as of December 31, 2008.

53

        The Trustee does not expect that the Trustee's disclosure controls and procedures relating to the Trust or the Trustee's internal control over financial reporting relating to the Trust will prevent all errors and all fraud. A registrant's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A registrant's internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified basis of accounting discussed above, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrant's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        Further, the design of disclosure controls and procedures and internal control over financial reporting must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.

        This annual report does not include an attestation report of the Trust's independent registered public accounting firm regarding internal control over financial reporting. The Trustee's report was not subject to attestation by the Trust's independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only the Trustee's report in this annual report.

54

PART III

Item 10.    Directors, Executive Officers and Corporate Governance.

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

        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 a board of directors, and therefore does not have an audit committee, an audit committee financial expert or a nominating committee.

Section 16(a) Beneficial Ownership Reporting Compliance

        The Trust 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 of ownership of Units and reports of changes in such ownership pursuant to Section 16 under the Securities Exchange Act of 1934. Based solely on a review of these reports, the Trust believes that the applicable reporting requirements of Section 16(a) of the Securities Exchange Act of 1934 were complied with for all transactions which occurred in 2008.

Item 11.    Executive Compensation.

        Not applicable.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

(a)

Security Ownership of Certain Beneficial Owners.

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

(1)

Under applicable regulations of the Securities and Exchange Commission, securities are deemed to be "beneficially" owned by a person who directly or indirectly holds or shares of voting power with respect thereto.

(2)

Based on information contained in the Form 4 filed on December 23, 2003 and Schedule 13D/A (Amendment No. 6) filed on December 14, 2005. These units of beneficial interest of the Issuer (the "Units") are owned directly by MOSH Holding, L.P., a Texas limited partnership ("MOSH"). MOSH Holding I, L.L.C., a Texas limited liability company ("MOSHLLC") is the sole general partner of MOSH and has sole investment discretion and voting authority with respect to the Units. Charles A. Sharman, Joseph F. Langston, Jr. and Timothy M. Roberson are the sole managers and members of MOSHLLC, in which capacity they may 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 Units except to the extent of their respective pecuniary interest therein.

55

(b)

Security Ownership of Management.    Not applicable.

(c)

Changes in Control.    Registrant knows of no arrangement, including the pledge of securities of the Registrant, the operation of which may at a subsequent date result in a change in control of the Registrant.

Item 13.    Certain Relationships and Related Transactions, and Director Independence.

        See Item 3. Legal Proceedings and Item 1. Business "—Legal Proceedings and Status of the Trust" and "—Timing of Liquidation" for a description of legal proceedings and related transactions among the Trustee, the Trust and certain unitholders of the Trust.

        On September 28, 2007, the Trust entered into a Demand Promissory Note agreement with JPMorgan in order to cover portions of its operating expenses. The lender approved an uncommitted line of credit to the Trust in a principal amount not to exceed $3 million. As part of that agreement, JPMorgan pays the expenses on behalf of the Trust. JPMorgan may decline to fund any request of the Trust for borrowings at anytime, for any reason, including the event that JPMorgan has reason to believe that the Trust will not be able to satisfy its obligation to repay the Demand Loans. Interest on the note is calculated at a rate per annum equal to Prime Rate plus two percent (2%), paid annually. The Demand Promissory Note is secured by a pledge of the Trust Estate, as that term is defined in the Trust Indenture, including without limitation the 99.99% general partnership interest in the Mesa Offshore Royalty Partnership owned by the Trust, pursuant to a Pledge Agreement dated September 29, 2007, as amended by the First Amendment to Pledge Agreement dated as of December 3, 2007, executed by the Trust for the benefit of the Lender. The Trust may borrow amounts under this Note until such time as JPMorgan makes demand for payment in full or December 31, 2008, whichever is earlier.

        On December 3, 2007, JPMorgan, individually and as lender, entered into an Amended and Restated Promissory Note, with the Trust as borrower, to amend the Demand Promissory Note to provide for, among other provisions, an extension of the stated maturity date of the Loans made pursuant to the Demand Promissory Note and the Amended and Restated Note until the earlier of (1) December 31, 2009, (2) 31 days after the Trust's receipt of any settlement proceeds, recovery or judgment in connection with the Lawsuit, (3) final liquidation of the Trust's assets, or (4) the Settlement Agreement is not approved by the Court. Additionally, the amendment provided that the Trust may continue to obtain loans under the note until the maturity date, as long as, the amount borrowed does not exceed $3 million and the loan is not in default. The amendment also provided that interest expense shall be due and payable on the maturity date.

        On August 25, 2008, the Trustee executed an amended and restated Demand Note that among other things increased the aggregate principal amount available for borrowing to $4.0 million and amended the definition of "Maturity Date" to delete the text relating to the failure of the Court to approve the prior Settlement Agreement.

        On January 28, 2009, the Trustee executed and delivered to JPMorgan a Third Amended and Restated Promissory Note, dated as of January 12, 2009, increasing the principal amount available for borrowing, subject to the terms of such note, to $5 million.

56

Item 14.    Principal Accounting Fees and Services

        The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional services firms and related fees are granted by the Trustee.

        The following table presents fees for professional audit services rendered by KPMG LLP for the audit of the Mesa Offshore Trust financial statements for 2008 and 2007 and fees billed for other services rendered by KPMG LLP.

		2008		2007
Audit fees(1)		$	235,000	$	195,000
Audit-related fees			—		—
Tax fees(2)			28,000		25,000
All other fees			—		—
	Total fees	$	263,000	$	220,000

(1)

Audit fees consist of fees for the audit of the Mesa Offshore Trust financial statements and reimbursement for travel-related expenses.



(2)

Tax fees consist of fees related to the Mesa Offshore Trust's tax information for its unitholders paid in 2008 related to 2007 tax work and paid in 2007 related to 2006 tax work.

57

PART IV

Item 15.    Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements

        The following financial statements are set forth under Part II, Item 8 of this Annual Report on Form 10-K on the pages indicated.

	Page in this Form 10-K
Statements of Distributable Income		36
Statements of Assets, Liabilities and Trust Corpus		36
Statements of Changes in Trust Corpus		36
Notes to Financial Statements		37
Report of Independent Registered Public Accounting Firm—KPMG LLP		52

(a)(2) Schedules

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

(a)(3) Exhibits

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

		SEC File or Registration Number		Exhibit Number
4(a)*	Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982		2-79673		10(gg)
4(b)*	Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty Partnership, dated December 15, 1982		2-79673		10(hh)
4(c)*	Partnership Agreement between Mesa Offshore Management Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982		2-79673		10(ii)
4(d)*	Amendment to Partnership Agreement between Mesa Offshore Management Co., Texas Commerce Bank National Association, as Trustee, and Mesa Operating Limited Partnership, dated December 27, 1985 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of Mesa Offshore Trust)		1-8432		4(d)
4(e)*	Amendment to Partnership Agreement between Texas Commerce Bank National Association, as Trustee, and Mesa Operating dated as of January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December 31, 1993 of Mesa Offshore Trust)		1-8432		4(e)
10(a)*	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
10(b)*	Demand Promissory Note, dated as of September 28, 2007 (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 3, 2007)		1-8432		10.1
10(c)*	Pledge Agreement, dated as of September 28, 2007 (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on October 3, 2007)		1-8432		10.2

58

		SEC File or Registration Number		Exhibit Number
10(d)*	Settlement Agreement and Release, effective December 3, 2007 by and among JPMorgan Chase Bank, N.A., JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust, and MOSH Holding, L.P., Intervenor-Plaintiff Dagger-Spine Hedgehog Corporation, and Intervenor-Plaintiffs Keith A. Wiegand, Ronnie McGlothlin, Gordon W. Bader, Roger L. Bean, Roger R. Bean, Jennifer J. Bean, Tracey M. Stump, Scott W. Bean, James Blau, Larry W. Bradley, Richard Brown, Scott Curran, Ron Davis, Mark Dittus, John C. Easton, Jamie Arnold, John Easton Schwab Brokerage, John Easton Schwab Roth, John Easton Schwab IRA, John Easton Scottrade Brokerage, John Easton Trust, Jamie Arnold Schwab IRA, Vicki Easton Schwab IRA, James Figielski, James Figielski Pension Plan, Ami Schecter, Ami Schecter Roth IRA, Kathleen Friend, Patricia L. Hendrix, Ben Hoos, Matt Hoos, Philip Hoos, John W. Hovanec, Nicole M. Kimball, Matthew J. King, Darrell M. Leis, J.D. Maddox, Roy G. Maddox, John McCall, Katrina McGlothlin, Mary R. McNamara, Michael E. McNamara, Monika Meier, Mallory Mikkelsen, Dean P. Miles, Elizabeth A. Miles-Cunningham, Lori Miles, Robert M. Miles, Sharon A. Miles, William Kevin Miles, Gara Sue Pelcher, Jeffrey T. Pelcher, The Pelcher Company Keogh Plan, Jeffrey Thomas Pelcher Custodial for Nathan Allen Pelcher Roth IRA, Gara Pelcher Ten Com, Jeffrey T. Pelcher Custodial for Derrick T. Pelcher, Jeffrey T. Pelcher Custodial for Nathan A. Pelcher, Adriene Rohleder, John Selep, John M. Speight, Gordon A. Stamper, Jessica Stamper, Armin Sternberg, Robert Todd, T.D. Tommey, Lyle Wagman, Barbara Wiedemann, Knut Wiedemann, Nichole Wiedemann, Jerry L. Wolf, and Galen R. Young (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on December 13, 2007)		1-8432		10.1
10(e)*	Letter Agreement dated December 7, 2007 Amending and Modifying Settlement Agreement and Release (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on December 13, 2007)		1-8432		10.2
10(f)*	Amended and Restated Promissory Note, dated December 3, 2007, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.3 to Form 8-K filed on December 13, 2007)		1-8432		10.3
10(g)*	First Amendment to Pledge Agreement, dated as of December 3, 2007, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.4 to Form 8-K filed on December 13, 2007)		1-8432		10.4
10(h)*	Second amended and Restated Promissory Note, dated June 25, 2008, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on September 2, 2008		1-8432		10.1
10(i)	Second Amendment to Pledge Agreement, dated June 25, 2008, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on September 2, 2008)		1-8432		10.2

59

		SEC File or Registration Number		Exhibit Number
10(j)	Third Amended and Restated Promissory Note, dated January 12, 2009, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 29, 2009)		1-8432		10.1
10(k)	Third Amendment to Pledge Agreement, dated as of January 12, 2009, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on January 29, 2009)		1-8432		10.2
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
99(a)	DeGolyer and MacNaughton Appraisal Report as of December 31, 2008 on Proved Reserves of Certain Interests owned by Mesa Offshore Trust

*

Previously filed with the Securities and Exchange Commission and incorporated herein by reference.

60

SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	MESA OFFSHORE TRUST
	By	JPMORGAN CHASE BANK, N.A., TRUSTEE
March 31, 2009	By:	/s/ MIKE ULRICH Mike Ulrich Vice President & Trust Officer The Bank of New York Mellon Trust Company, N.A., as attorney-in-fact for the Trustee

        The Registrant, Mesa Offshore Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided.

61

EXHIBIT INDEX

Exhibit Number			SEC File or Registration Number		Exhibit Number
	4(a)*	Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982		2-79673		10(gg)
	4(b)*	Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty Partnership, dated December 15, 1982		2-79673		10(hh)
	4(c)*	Partnership Agreement between Mesa Offshore Management Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982		2-79673		10(ii)
	4(d)*	Amendment to Partnership Agreement between Mesa Offshore Management Co., Texas Commerce Bank National Association, as Trustee, and Mesa Operating Limited Partnership, dated December 27, 1985 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of Mesa Offshore Trust)		1-8432		4(d)
	4(e)*	Amendment to Partnership Agreement between Texas Commerce Bank National Association, as Trustee, and Mesa Operating dated as of January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December 31, 1993 of Mesa Offshore Trust)		1-8432		4(e)
	10(a)*	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
	10(b)*	Demand Promissory Note, dated as of September 28, 2007 (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 3, 2007)		1-8432		10.1
	10(c)*	Pledge Agreement, dated as of September 28, 2007 (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on October 3, 2007)		1-8432		10.2
	10(d)*	Settlement Agreement and Release, effective December 3, 2007 by and among JPMorgan Chase Bank, N.A., JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust, and MOSH Holding, L.P., Intervenor-Plaintiff Dagger-Spine Hedgehog Corporation, and Intervenor-Plaintiffs Keith A. Wiegand, Ronnie McGlothlin, Gordon W. Bader, Roger L. Bean, Roger R. Bean, Jennifer J. Bean, Tracey M. Stump, Scott W. Bean, James Blau, Larry W. Bradley, Richard Brown, Scott Curran, Ron Davis, Mark Dittus, John C. Easton, Jamie Arnold, John Easton Schwab Brokerage, John Easton Schwab Roth, John Easton Schwab IRA, John Easton Scottrade Brokerage, John Easton Trust, Jamie Arnold Schwab IRA, Vicki Easton Schwab IRA, James Figielski, James Figielski Pension Plan, Ami Schecter, Ami Schecter Roth IRA, Kathleen Friend, Patricia L. Hendrix, Ben Hoos, Matt Hoos, Philip Hoos, John W. Hovanec, Nicole M. Kimball, Matthew J. King, Darrell M. Leis, J.D. Maddox, Roy G. Maddox, John McCall, Katrina McGlothlin, Mary R. McNamara, Michael E. McNamara, Monika Meier, Mallory Mikkelsen, Dean P. Miles, Elizabeth A. Miles-Cunningham, Lori Miles, Robert M. Miles, Sharon A. Miles, William Kevin Miles, Gara Sue Pelcher, Jeffrey T. Pelcher, The Pelcher Company Keogh Plan, Jeffrey Thomas Pelcher Custodial for Nathan Allen Pelcher Roth IRA, Gara Pelcher Ten Com, Jeffrey T. Pelcher Custodial for Derrick T. Pelcher, Jeffrey T. Pelcher Custodial for Nathan A. Pelcher, Adriene Rohleder, John Selep, John M. Speight, Gordon A. Stamper, Jessica Stamper, Armin Sternberg, Robert Todd, T.D. Tommey, Lyle Wagman, Barbara Wiedemann, Knut Wiedemann, Nichole Wiedemann, Jerry L. Wolf, and Galen R. Young (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on December 13, 2007)		1-8432		10.1

62

Exhibit Number			SEC File or Registration Number		Exhibit Number
	10(e)*	Letter Agreement dated December 7, 2007 Amending and Modifying Settlement Agreement and Release (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on December 13, 2007)		1-8432		10.2
	10(f)*	Amended and Restated Promissory Note, dated December 3, 2007, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.3 to Form 8-K filed on December 13, 2007)		1-8432		10.3
	10(g)*	First Amendment to Pledge Agreement, dated as of December 3, 2007, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.4 to Form 8-K filed on December 13, 2007)		1-8432		10.4
	10(h)*	Second Amended and Restated Promissory Note, Dated August 25, 2008, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on September 2, 2008		1-8432		10.1
	10(i)	Second Amendment to Pledge Agreement, dated June 25, 2008, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on September 2, 2008)		1-8432		10.2
	10(j)	Third Amended and Restated Promissory Note, dated January 12, 2009, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 29, 2009)		1-8432		10.1
	10(k)	Third Amendment to Pledge Agreement, dated as of January 12, 2009, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on January 29, 2009)		1-8432		10.2
	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
	99(a)	DeGolyer and MacNaughton Appraisal Report as of December 31, 2008 on Proved Reserves of Certain Interests owned by Mesa Offshore Trust

*

Previously filed with the Securities and Exchange Commission and incorporated herein by reference.

63

EX-31

Exhibit 31

I, Mike Ulrich, certify that:

        1.     I have reviewed this quarterly report on Form 10-K of Mesa Offshore Trust, for which JPMorgan Chase Bank, N.A. acts as Trustee;

        2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

        3.     Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, cash earnings and distributions and changes in trust corpus of the registrant as of, and for, the periods presented in this report;

        4.     I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), or for causing such controls and procedures to be established and maintained, for the registrant and have:

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this quarterly report is being prepared;



b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the basis of accounting described in Note 5;



c)

evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



d)

disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

        5.     I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors:

a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and



b)

any fraud, whether or not material, that involves any persons who have a significant role in the registrant's internal control over financial reporting.

In giving the foregoing certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by the Working Interest Owners and the Managing General Partner of Mesa Offshore Trust Partnership, in which the registrant owns a 99.99% interest.

/s/ Mike Ulrich
Mike Ulrich
Vice President and Trust Officer
The Bank of New York Mellon Trust Company, N.A.,
as attorney-in-fact for the Trustee

Date: March 31, 2009

EX-32

Exhibit 32

March 31, 2009

Via EDGAR

Securities and Exchange Commission
Judiciary Plaza
450 Fifth Street, N.W.
Washington, D.C. 20549

RE:

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002

Ladies and Gentlemen:

        In connection with the Quarterly Report of Mesa Offshore Trust (the "Trust") on Form 10-K for the year ended December 31, 2008, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

        (1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

        (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

        The above certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and is not being filed as part of the Form 10-K or as a separate disclosure document.

JPMORGAN CHASE BANK, N.A.,
Trustee for Mesa Offshore Trust

/s/ Mike Ulrich
Mike Ulrich
Vice President and Trust Officer
The Bank of New York Mellon Trust Company, N.A.,
as attorney-in-fact for the Trustee

EX-99.(A)

Exhibit 99.(a)

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

APPRAISAL REPORT

as of

DECEMBER 31, 2008

on

CERTAIN INTERESTS

owned by

MESA OFFSHORE TRUST

prepared for

THE BANK of NEW YORK TRUST COMPANY, N.A.

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

APPRAISAL REPORT

as of

DECEMBER 31, 2008

on

CERTAIN INTERESTS

owned by

MESA OFFSHORE TRUST

prepared for

THE BANK of NEW YORK TRUST COMPANY, N.A.

FOREWORD

Scope of Investigation

This report presents an appraisal,as of December 31, 2008, of the estimates of the extent of the proved, probable, and possible crude oil, condensate, and natural gas reserves and the estimates of the value of the proved and proved-plus-probable reserves of royalty interests in certain properties owned by the Mesa Offshore Trust (MOST) located offshore from Louisiana and Texas in the Gulf of Mexico. Also presented are estimates of the extent only of the possible oil, condensate, and gas reserves. The Managing General Partner is Pioneer Natural Resources USA Inc. (PNR). This report was prepared at the request of The Bank of New York Trust Company, N.A. (Bank of New York), trustee for MOST.

Estimates of proved reserves presented in this report have been prepared in compliance with the regulations promulgated by the United States Securities and Exchange Commission (SEC). Estimates of probable and possible reserves presented in this report have been prepared in accordance with the Petroleum Resources Management System (PRMS) approved in March 2007 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. These reserves definitions are discussed in detail in the Definition of Reserves section of this report.

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2008. Net reserves are defined as that portion of the gross reserves attributable to MOST’s interests after deducting royalties and interests owned by others.

This report presents values that were estimated for proved and proved-plus-probable reserves using initial prices provided by Bank of New York and initial costs provided by PNR. Future price and cost assumptions were provided by Bank of New York. A detailed explanation of the price and cost assumptions used herein is included in the Valuation of Reserves section of this report.

Values are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated operating expenses and capital costs from the future gross revenue. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. In this report, present worth values using a nominal discount rate of 10 percent are reported in detail and values using nominal discount rates of 5, 15, 20, and 25 percent are reported as totals in the appendix to this report.

Estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Authority

This report was authorized by Mr. Mike Ulrich, Vice President, Bank of New York.

2

Source of Information

Information used in the preparation of this report was obtained from PNR’s files on behalf of Bank of New York, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by PNR and Bank of New York with respect to property interests, production from such properties, current costs of operation and development, current prices for production, the future plans for development of the properties, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

3

DEFINITION of RESERVES

Petroleum reserves included in this report that are classified as proved are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs as of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. Proved reserves classifications used in this report are in accordance with the reserves definitions of Rules 4—10(a) (1)—(13) of Regulation S—X of the SEC of the United States. The petroleum reserves are classified as follows:

Proved oil and gas reserves — Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an

4

installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite, and other such sources.

Proved developed oil and gas reserves — Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves — Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques

5

have been proved effective by actual tests in the area and in the same reservoir.

The probable and possible reserves presented in this report have been prepared in accordance with the PRMS approved in March 2007 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. Probable and possible reserves are based on geoscience and/or engineering data similar to that used in estimates of proved reserves, but technical or other uncertainties preclude such reserves being classified as proved.

Probable Reserves — Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

Possible Reserves — Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

The extent to which probable and possible reserves ultimately may be recategorized as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. Probable and possible reserves in this report have not been adjusted in consideration of these additional risks to make them comparable to proved reserves.

6

ESTIMATION of RESERVES

Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

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

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, and the structural positions of the properties.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on current economic conditions.

The rates used for future oil, condensate, and gas production are estimated to be within the capacity of a well or reservoir to produce. Data available from wells drilled on the appraised properties through December 31, 2008, were used to prepare the estimates shown herein. Gross production through December 31, 2008, was deducted from the gross ultimate recovery to arrive at estimates of gross reserves.

Gas quantities estimated herein are expressed as sales gas at a temperature base of 60 degrees Fahrenheit (°F) and a pressure base of 14.73 pounds per square inch absolute (psia). Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation

7

and processing. Condensate reserves estimated herein are those to be obtained by normal separator recovery.

Estimates of the gross and net proved, probable, and possible reserves, as of December 31, 2008, of the properties appraised are presented as follows. Oil and condensate reserves are expressed in barrels (bbl) and gas reserves are expressed in thousands of cubic feet (Mcf).

	Oil and Condensate (bbl)	Sales Gas (Mcf)
Gross Reserves
Proved	79,016	3,034,618
Probable*	4,290	1,430,000
Possible*	12,270	4,090,000
Net Reserves
Proved	6,082	213,299
Probable*	193	64,350
Possible*	551	184,050

*Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.

8

VALUATION of RESERVES

This report has been prepared using initial prices provided by Bank of New York and initial costs provided by PNR on behalf of Bank of New York. Future prices were estimated using guidelines established by the United States Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB). In this report, values for proved and proved-plus-probable reserves were based on projections of estimated future production and revenue prepared for these properties with no risk adjustment applied to the probable reserves. Probable reserves involve substantially higher risks than proved reserves. Revenue values for proved-plus-probable reserves have not been adjusted to account for such risks; this adjustment would be necessary in order to make values for proved-plus-probable reserves comparable with values for proved reserves.

Oil and Condensate Prices

Initial oil and condensate prices furnished by Bank of New York are $44.60 per barrel and were held constant for the producing lives of the properties.

Natural Gas Prices

The natural gas prices furnished by Bank of New York varied from $5.71 to $5.84 per thousand cubic feet of gas and were held constant for the producing lives of the properties.

Operating Expenses and Capital Costs

The properties appraised are royalties. Therefore, no operating expenses are incurred.

9

The estimated future revenue to be derived from the production and sale of MOST’s net proved and proved-plus-probable reserves, as of December 31, 2008, under the economic assumptions furnished by Bank of New York is summarized as follows, expressed in dollars ($):

	Proved ($)	Proved plus Probable* ($)
Future Gross Revenue	1,493,534	1,878,033
Operating Expenses	0	0
Capital Costs	0	0
Future Net Revenue**	1,493,534	1,878,033
Present Worth at 10 Percent**	1,251,878	1,517,518

*	Values for probable reserves have not been risk adjusted to make them comparable to values for proved reserves.
**	Future income tax expenses were not taken into account in the preparation of these estimates.

The appendix bound with this report presents tabulations and projections of revenue from the proved and non-risk-adjusted proved-plus-probable reserves for the interests appraised. Also included are summaries of the probable and possible reserves.

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

10

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

11

SUMMARY and CONCLUSIONS

Evaluated herein are royalty interests in certain properties owned by MOST located offshore from Louisiana and Texas in the Gulf of Mexico. Estimates of MOST’s net proved, probable, and possible reserves, as of December 31, 2008, of the properties appraised are presented as follows. Oil and condensate reserves are expressed in barrels (bbl) and gas reserves are expressed in thousands of cubic feet (Mcf).

	Proved	Probable*	Possible*
Net Oil and Condensate, bbl	6,082	193	551
Net Sales Gas, Mcf	213,299	64,350	184,050

*Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.

Estimated revenue and costs attributable to MOST’s interests in the proved and proved-plus-probable reserves, as of December 31, 2008, of the properties evaluated under the aforementioned assumptions concerning future prices and costs are summarized as follows, expressed in dollars ($):

	Proved ($)	Proved plus Probable* ($)
Future Gross Revenue	1,493,534	1,878,033
Operating Expenses	0	0
Capital Costs	0	0
Future Net Revenue**	1,493,534	1,878,033
Present Worth at 10 Percent**	1,251,878	1,517,518

*	Values for probable reserves have not been risk adjusted to make them comparable to values for proved reserves.
**	Future income tax expenses were not taken into account in the preparation of these estimates.

12

Gas quantities estimated herein are expressed at a temperature base of 60 °F and a pressure base of 14.73 psia.

	Submitted,
	DeGOLYER and MacNAUGHTON
SIGNED: March 10, 2009
	/s/ Paul J. Szatkowski, P.E.
	Paul J. Szatkowski, P.E.
	Senior Vice President
	DeGolyer and MacNaughton

13

TABLE of CONTENTS

	Page
FOREWORD	1
Scope of Investigation	1
Authority	2
Source of Information	3
DEFINITION of RESERVES	4
ESTIMATION of RESERVES	7
VALUATION of RESERVES	9
SUMMARY and CONCLUSIONS	12
APPENDIX