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TABLE OF CONTENTS
PART IV

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, 2009
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 whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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 the 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, 2009, of $0.12 was approximately $8,637,625.92.

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 30, 2010, 71,980,216 Units of Beneficial Interest were outstanding in Mesa Offshore Trust.

DOCUMENTS INCORPORATED BY REFERENCE: None.

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		Page

PART I
Item 1.	Business	3
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	17
Item 2.	Properties	18
Item 3.	Legal Proceedings	18
Item 4.	[Reserved]	18
PART II
Item 5.	Market for the Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	19
Item 6.	Selected Financial Data	19
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	27
Item 8.	Financial Statements and Supplementary Data	28
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	48
Item 9A.	Controls and Procedures	48
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	49
Item 11.	Executive Compensation	49
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	50
Item 13.	Certain Relationships and Related Transactions, and Director Independence	50
Item 14.	Principal Accounting Fees and Services	51
PART IV
Item 15.	Exhibits, Financial Statement Schedules	52
SIGNATURES		54

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 "—Status of the Trust, Timing of Liquidation and Legal Proceedings" 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 $359,000, $181,000 and $177,000 for the years 2009, 2008 and 2007, respectively. The Termination Threshold was met in each of the three consecutive years ending December 31, 2004.

Due to litigation involving the Trust that challenged whether the Termination Threshold was in fact 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. The Trustee entered into a Final Settlement Agreement on May 18, 2009. On August 6, 2009, the court responsible for the litigation initially approved the Final Settlement Agreement and issued its Findings of Fact and Conclusions of Law With Respect to Final Settlement Agreement. On September 14, 2009, the court signed its Final Judgment, resolving all parties and all claims in the lawsuit. Pioneer completed the sale of the West Delta 61 properties effective December 1, 2009. The Final Judgment became binding and non-appealable on February 1, 2010. For further descriptions of these matters, see "—Status of the Trust, Timing of Liquidation and Legal Proceedings."

As part of the liquidation and termination of the Trust, the Trustee has set February 22, 2010 as the record date for unitholders entitled to payments of any final liquidating distributions. The Trustee has also announced, and on or about March 24, 2010 has paid, an initial liquidating distribution of $0.116238 per unit. The Trustee will make one or more final liquidating distributions to unitholders of any funds remaining after all Trust liabilities have been satisfied.

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.

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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 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 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 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.

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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 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

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purposes. Bank of New York Trust Company, 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. Unitholders whose units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.

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. Proceeds from sale of royalty properties are also considered 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.

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

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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.

STATUS OF THE TRUST, TIMING OF LIQUIDATION AND LEGAL PROCEEDINGS

Status of the Trust and 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 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 challenged whether the Termination Threshold was in fact 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.

Pursuant to the Final Settlement Agreement described below, the Trustee has directed the sale or other final disposition of the properties owned by the Partnership as part of the termination and liquidation of the Trust. As part of the liquidation and termination of the Trust, the Trustee has set February 22, 2010 as the record date for unitholders entitled to payments of any final liquidating distributions. The Trustee has also announced, and on or about March 24, 2010 has paid, an initial liquidating distribution of $0.116238 per unit. The Trustee will make one or more final liquidating distributions to unitholders of any funds remaining after all Trust liabilities have been satisfied.

Pioneer has informed the Trustee that it expects to commence plugging and abandonment, or other disposition, of the Partnership's remaining property on the Brazos A-39 Block during the first quarter of 2010. The Trustee expects to make a final liquidating distribution as promptly as practicable after such event, if there are any remaining proceeds after all of the Trust's liabilities have been paid by the Trustee.

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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 was subsequently transferred to 334th Judicial District of Harris County, 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) an alleged breach of fiduciary duty. The remedies MOSH sought included (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 sixty-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 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 sought 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

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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 ever identified a willing qualified successor Trustee that was not also a lender under one of Pioneer's credit facilities (which status MOSH contended was 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 was 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

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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 was 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 to the Trustee 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 Minerals 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, but was subsequently shut in again on September 2, 2009, and has been off production ever since. The lease expired 180 days after last production.

Given its conclusion that the Trust was better off with the post-farmout override, and hoping to end this 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 did not have the legal right to sue Pioneer because the claims belonged 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 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

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(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.

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 (through 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 was 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 again 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 to intervene in the Lawsuit. At the public auction on March 18, 2009, no bids were submitted for the Partnership assets, in the face 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. On April 15, 2009 and May 9, 2009, respectively, unitholders Michael Brown and Benjamin Ginter filed additional interventions (collectively, along with other individuals previously defined as such, the "Individual Intervenors").

On May 18, 2009, the Trustee, on behalf of the Trust, entered into a Final Settlement Agreement with (1) the Plaintiffs, both in their individual capacities and as claimed representatives of the Trust and/or the unitholders, (2) Pioneer and (3) Woodside. The terms of the Final Settlement Agreement included the following: (a) Pioneer would pay to the Trust $13 million and would sell and contribute to the Trust any proceeds from the sale of all of its interests in the Brazos Block A-39 (the "Pioneer Settlement Interests"); (b) Trustee would pay to the Trust $5 million and would release all claims for and forgive repayment of the existing $5 million Demand Promissory Note (the "Credit Facility") provided by JPMorgan, as lender, to the Trust; and (c) Woodside would pay to the Trust $1 million. Notwithstanding certain other releases, the Trustee will be permitted to use the remaining balance available under the Credit Facility and any other Trust income to pay Trust liabilities and expenses as permitted under the Trust Indenture prior to the final distribution of any net settlement proceeds. These liabilities and expenses include any out-of-pocket costs incurred for effecting the sale of assets in the Liquidation Process and for any other fees and expenses relating to the administration of the Trust after April 27, 2009. As provided in the Final Settlement Agreement, each of the parties agreed to release any and all claims against the other parties that are, or could have been, asserted in the Lawsuit, including any claims for reimbursement of attorneys' fees or costs, except as provided for under the Final Settlement Agreement.

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On June 15, 2009, a group of unitholders, most of whom were part of the former group led by Keith A. Wiegand that had previously voluntarily non-suited their claims, submitted a filing to the Court, seeking to delay certain issues from being heard at the June 18, 2009 settlement hearing. This group of unitholders is referred to herein as the "2009 Unit Holder Group." On June 18, 2009 and July 23, 2009, the Court held evidentiary hearings on the fairness of the Final Settlement Agreement. The purpose of these hearings was for the Court to determine whether the Final Settlement Agreement should be approved as being in the best interests of the Trust and its unitholders/beneficiaries. The Individual Intervenors, the 2009 Unit Holder Group, and all other objectors were afforded the opportunity to participate in the hearings.

The Court considered all of the papers filed, the evidence presented, and arguments both for and against the Final Settlement Agreement, and, on August 6, 2009, approved the Final Settlement Agreement and denied all objections thereto. In its Findings of Fact and Conclusions of Law With Respect to Final Settlement Agreement ("Findings of Fact and Conclusions of Law"), the Court ruled that all claims that were raised (or that could have been raised) against the defendants in the Lawsuit were owned by the Trust and/or the Partnership; the Plaintiffs pursued the claims asserted in the Lawsuit on behalf of the Trust and/or the Partnership; the Plaintiffs and the Trustee had the authority to prosecute, resolve, settle and release all released claims on behalf of the Trust, the Partnership and the Plaintiffs; and the settlement was in the best interest of the Trust and its unitholders. The Court also entered findings that full and proper notice of the Lawsuit, the Final Settlement Agreement, and the settlement fairness hearing was provided to all unitholders and that all unitholders were given the opportunity to obtain the related documents and express any objections they may have had regarding the Final Settlement Agreement. The Court considered these unitholder objections in entering the Findings of Fact and Conclusions of Law, and denied all of them.

The initial judgment by the Court was interlocutory, meaning that it was not yet final, because, while the Court found that all unitholders were fully and properly notified of the Final Settlement Agreement and the related hearing, the Court indicated in its Findings of Fact and Conclusions of Law that it did not appear that the Individual Intervenors were provided notice that the motions to strike their petitions in intervention, filed by Pioneer, would be considered by the Court at the same time as the settlement agreement. Therefore, although the Court denied all of the Individual Intervenors' objections to the settlement, the Court also wanted to consider the related motions to strike their petitions in intervention before entering a final judgment in the Lawsuit.

On July 10, 2009, the Trustee mailed a notice to all unitholders of record, announcing that the Termination Threshold had been met and that, in accordance with the Trust Indenture and Final Settlement Agreement, it had instructed Pioneer to sell the oil and gas assets of the Partnership at public auction on August 12, 2009 through The Oil & Gas Asset Clearinghouse. However, given the interlocutory nature of the Court's August 6, 2009 judgment, the settling parties agreed to postpone the public auction until after the Court entered final judgment.

On September 14, 2009, the Court signed its Final Judgment, resolving all parties and all claims in the Lawsuit. This Final Judgment granted the defendants' motion for summary judgment and motion to dismiss claims of Intervenors Keith Wiegand, Robert Miles, Gordon Stamper, Michael Brown, and Benjamin Ginter. Robert Miles non-suited his intervention prior to argument on these motions. The Final Judgment also denied the motion for sanctions filed by Gordon Stamper, and adopted and incorporated the August 6, 2009 Findings of Fact and Conclusions of Law. Thus, there are no longer any issues remaining before the Court, all objections to the Final Settlement Agreement are overruled and denied, all pending petitions in interventions are dismissed, and all related intervenors' claims are dismissed. Additionally, all other claims by parties to the Lawsuit, to the extent not otherwise addressed by the Final Judgment, are dismissed with prejudice. On October 19, 2009, Gordon Stamper filed a petition for writ of mandamus in the Houston Fourteenth Court of Appeals, related to a September 10, 2009 order denying his motion to recuse the Judge presiding over the Lawsuit. The Houston

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Fourteenth Court of Appeals denied his petition for writ of mandamus in an opinion dated November 3, 2009. Also on November 3, 2009, Gordon Stamper filed a "Motion to Appeal" in the Court, and this Motion was assigned to the Houston Fourteenth Court of Appeals. On December 3, 2009, the Court of Appeals issued a memorandum opinion dismissing the appeal, and the appeal became final on February 1, 2010.

Given the entry of the Final Judgment, the Trustee directed Pioneer to sell the assets of the Mesa Offshore Royalty Partnership (the "Partnership assets") (along with the Pioneer Settlement Interests), consistent with the terms contained in the Final Settlement Agreement, and as approved by the Court in the Final Judgment, at public auction on November 11, 2009 through The Oil & Gas Asset Clearinghouse. Notice of the public auction was mailed to the unitholders of record at least thirty days before the sale.

At the public auction, the Partnership assets and the assets contributed to the Trust by Pioneer for sale pursuant to its tender letter of October 10, 2008 (hereafter referred to as "Pioneer Settlement Interests") were offered in two lots: (1) the West Delta 61 Lot; and (2) the Brazos A-39 Lot (together, the "Sales Lots"). There was no right of first refusal as previously considered, and the two lots were offered for sale to the highest bidder(s). The highest bidder for the West Delta 61 Lot was Emerald Energy, with a purchase price of $700,000. The Brazos A-39 Lot, including interests owned by the Partnership and assets contributed to the Trust by Pioneer for sale pursuant to a tender letter, did not receive any bids. Since this liquidation process did not result in the sale of Pioneer's interests in Brazos Block A-39, by letter dated January 11, 2010, Pioneer Natural Resources informed the Trust that Pioneer proposed to its co-working interest owner in the Brazos A-39 #5 well, Woodside, that the well, platform and related facilities should be abandoned pursuant to an operating agreement governing the property. Woodside agreed to this by election dated January 8, 2010. As a result, the Brazos A-39 lease will lapse and revert to the U.S. government, and all of the interests in the lease held by each of Pioneer, Woodside and the Partnership will be extinguished. Production from the Brazos A-39 #5 well was relied upon to maintain the Brazos A-39 lease, but the well was shut in by a pipeline purchaser on September 2, 2009 because the production does not meet pipeline specifications. The lease expired 180 days after last production. Based on these events, Pioneer has informed the Trust that it is moving forward with the final accounting relating to the termination, liquidation and wind-up of the Partnership in accordance with the Final Settlement Agreement and the Partnership's First Amended and Restated Articles of General Partnership. Pioneer expects to commence that process by the end of the first quarter 2010.

Based on the sale or abandonment by the Partnership of all of the overriding royalty and other interests conveyed to the Partnership pursuant to the Conveyance, and based on the Settlement Agreement becoming final and non-appealable on February 1, 2010, the Trust will terminate at such effective time in accordance with Section 9.02 of the Trust Indenture and with the Settlement Agreement. The Trustee closed the Trust's unit transfer books and no further unit transfers were recognized after the close of business on February 22, 2010, the record date for the Trust's liquidating distributions. Although the Trust cannot control trading, trading of the Trust's common units on the OTC Bulletin Board should have also ceased. There were 71,980,216 units of beneficial interest in the Trust outstanding as of the close of business on February 22, 2010. The Trustee made its first liquidating distribution of approximately $8,373,000 ($0.116328 per unit) on March 24, 2010, to unitholders of record as of February 22, 2010.

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thereon) under the existing $5 million Demand Promissory Note in accordance with the terms of the Final Settlement Agreement effective March 24, 2010. Amounts remaining after the completion of the termination of the Trust, if any, will be paid to unit holders as of the February 22, 2010 record date in one or more final liquidating distributions.

The Trustee will continue to act as Trustee and exercise its powers for the purpose of liquidating and winding up the affairs of the Trust at its termination until its duties have been fully performed and the Trust estate is finally distributed. In accordance with the Trust Indenture, the Trustee will as promptly as possible distribute the remaining assets in the Trust estate, if any, after paying, satisfying and discharging all of the liabilities of the Trust, or, when necessary, setting up reserves in such amounts as the Trustee in its discretion deems appropriate for contingent liabilities.

Assets and Liabilities in the Process of Liquidation

As a result of the triggering of the Termination Threshold effective January 1, 2005, the Trust is in the process of liquidation. After the Final Settlement Agreement was approved and Final Judgment was entered by the Court in the Lawsuit, the Trustee directed Pioneer to sell the Partnership assets (along with the Pioneer Settlement Interests), consistent with the terms contained in the Term Sheet and as approved by the Court, at public auction and any resulting sales proceeds will be remitted to the Trust as part of the wind-down process. See "—Status of Trust, Timing of Liquidation and Legal Proceedings" above. The below table presents the assets of the Trust at their estimated fair value as of December 31, 2009:

		December 31, 2009

ASSETS
Cash and short term investments		$	302,164
Net overriding royalty interest in oil and gas properties			0

	Total assets		302,164

LIABILITIES
Reserve for Trust expenses		$	302,164
Trust expenses payable			75,055
Interest Payable			480,443
Advances from JPMorgan			599,718
Note payable—JPMorgan			5,000,000

	Total liabilities		6,457,380

Net liabilities in process of liquidation		$	(6,155,216	)

The net overriding royalty interest in oil and gas properties at December 31, 2009 reflects the Trustee's estimate of value (in the absence of third-party appraisals or evaluations), based on information provided by Pioneer regarding the sole remaining interest of the Partnership in Brazos A-39, which was in the process of being plugged and abandoned, or otherwise disposed of.

DESCRIPTION OF ROYALTY PROPERTIES

Producing Acreage and Wells as of December 31, 2009

As of December 31, 2009, the Trust had no producing properties. As disclosed elsewhere in this Form 10-K, the remaining properties in which the Trust had an interest were either sold during 2009 or are in the process of being plugged and abandoned.

Reserves

As of December 31, 2009, the Trust had no proved reserves. As disclosed elsewhere in this Form 10-K, the remaining properties in which the Trust had an interest were either sold during 2009 or are in the process of being plugged and abandoned.

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CONTRACTS

General

PNR has advised the Trust that during 2009 its offshore gas production was marketed under short-term contracts at spot market prices primarily to TOTAL S.A. Spot market prices for natural gas in 2009 were generally lower than spot market prices in 2008.

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. See Item 7 of this Form 10-K and Note 4 in the Notes to Financial Statements for amounts withheld as of December 31, 2009 and amounts to be withheld in the future.

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.

The Trust is party to a Demand Promissory Note, and the Trust will incur taxable income associated with the cancellation of this note pursuant to the 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. 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, 2009 was a Prime Rate of 3.25%, plus 2% for a combined rate of 5.25%.

As of December 31, 2009, there was outstanding $5.0 million of principal outstanding under the Demand Promissory Note, together with $480,443 of accrued and unpaid interest expense. Effective March 24, 2010, the Demand Promissory Note was cancelled pursuant to the Settlement Agreement. The cancellation of indebtedness associated with this note will constitute cancellation of indebtedness income for federal income tax purposes. See "Business—Status of the Trust, Timing of Liquidation and Legal Proceedings" contained in Item 1 of this Form 10-K.

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 31, 2009, 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.

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,

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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 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.

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, 2009.

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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—Status of the Trust, Timing of Liquidation and Legal Proceedings" contained in Item 1 of this Form 10-K.

Item 4. [Reserved].

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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 Trust units are currently eligible for trading on the OTC Bulletin Board under ticker symbol MOSH.OB. In 2007 and 2008, the Trust had no Royalty income. The Trust has terminated and is in the process of liquidation. The Trustee has set February 22, 2010 as the record date for unitholders entitled to payments of any final liquidating distributions. Accordingly, only unitholders of record as of the February 22, 2010 record date will be entitled to payments by the Trust of any final liquidating distributions. The Trustee has also announced, and on or about March 24, 2010 has paid, an initial liquidation distribution of $0.116238 per unit.

The high and low sales prices and distributions per unit for each quarter in the two years ended December 31, 2009 were as follows:

	2009						2008

	High		Low		Distribution Paid		High		Low		Distribution Paid
First Quarter	$	0.41	$	0.11	$	—	$	0.50	$	0.10	$	—
Second Quarter	$	0.39	$	0.11	$	—	$	0.41	$	0.17	$	—
Third Quarter	$	0.17	$	0.08	$	—	$	0.42	$	0.15	$	—
Fourth Quarter	$	0.14	$	0.09	$	—	$	0.50	$	0.17	$	—

At March 31, 2010, the 71,980,216 units outstanding were held by 10,147 unitholders of record.

Item 6. Selected Financial Data.

	2009		2008		2007			2006			2005

Royalty income	$	430,106	$	—	$	—		$	145,642		$	2,284,914
Proceeds from sale of royalty properties	$	654,660	$	—	$	—		$	—		$	—
Distributable income	$	—	$	—	$	—		$	—		$	—
Distributable income per unit	$	—	$	—	$	—		$	—		$	—
Accumulated deficit at year end(1)	$	—	$	—	$	(1,477,002	)	$	(1,417,808	)	$	—
Expenses Payable(2)	$	75,055	$	270,595	$	190,955			—			—
Trust Accrued Interest Expense	$	480,443	$	230,440	$	31,187			—			—
Advances Payable—JPMorgan(3)	$	599,718		—		—			—			—
Note Payable—JPMorgan(4)	$	5,000,000	$	3,557,646	$	1,673,617		$	—		$	—
Total assets at year end	$	302,164	$	3,006	$	5,906		$	802,981		$	1,851,428

(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 loans under the Demand Promissory Note with JPMorgan and other advances payable to JPMorgan were used to pay $2,042,072 of the Trust's general and administrative expenses of $2,629,257 for the year ended December 31, 2009 and $270,595 of accrued expenses from 2008. The Trust had unpaid expenses of $75,055 as of December 31, 2009. The reserve for Trust expenses and loans 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

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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.

(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. As of December 31, 2009, JPMorgan had advanced $599,718 to the Trust in addition to amounts outstanding under the Demand Promissory Note. The Trust Indenture prohibits the Trustee from making any distributions to unitholders until these advances are repaid in full.
(4): Based on 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 as amended on December 3, 2007, August 25, 2008 and January 12, 2009, in which loans were advanced by the lender from time to time not to exceed $5 million. This Demand Promissory Note was used to pay unpaid administrative expenses related to the operation of the Trust. As of December 31, 2009, there was $5.0 million outstanding under the Demand Promissory Note. The Demand Promissory Note, and all principal and accrued and unpaid interest thereon, was canceled effective March 24, 2010 pursuant to the Settlement Agreement.

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 to the Financial Statements 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, 2009 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, general and administrative expenses would be recorded in the month they accrue, and accounting principles generally accepted in the United States would require a liquidation basis of accounting.

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Status of the Trust

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 directly challenged whether the Termination Threshold had 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. However, due to the continuation of the litigation for more than four years, the related cost to the Trust, the threat that the properties might soon 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, and the Court had allowed a public auction of these assets to go forward. The Trustee therefore instructed Pioneer to proceed with a public auction of the Partnership's assets on March 18, 2009, and Pioneer complied; but there were no bids submitted at the auction, in the face of the pending litigation by the Plaintiffs described in Part I, Item I, Financial Statements, Note 2. The Trustee then provided notice of another public auction of the Partnership's oil and gas assets, to be held on August 12, 2009. However, this public auction did not go forward, based on a judgment dated August 6, 2009, in which the Court approved the parties' settlement agreement (as detailed in "Business—Status of the Trust, Timing of Liquidation and Legal Proceedings" contained in Item 1 of this Form 10-K), but held that there was an outstanding procedural issue that needed to be addressed prior to entry of final judgment. The parties to the settlement agreement therefore decided to postpone the sale of the Partnership's oil and gas assets until the Court entered final judgment resolving all issues in the litigation, which took place on September 14, 2009. In accordance with the final judgment and the settlement agreement, the Trustee instructed Pioneer to proceed with a public auction of the Partnership's assets on November 11, 2009. At the November 11, 2009 auction, the highest bidder for the Partnership's assets in the West Delta 61 Block was Emerald Energy, with a sales price of $700,000. The assets of the Partnership and Pioneer in the Brazos A-39 Block did not receive any bids in the auction. Pioneer is entitled to dispose of the Brazos A-39 Block assets in any manner it sees fit. The Trustee has been informed that Pioneer expects to commence plugging and abandoning the property or otherwise to dispose of the property during the first quarter of 2010. Any resulting sales proceeds will be remitted to the Trust as part of the wind-down process. The Trustee has no authority or discretionary control over the timing of these plugging and abandonment expenditures or timing.

Financial and Operational Review

As discussed in Item 1 of this Form 10-K, PNR has advised the Trust that during 2009, its offshore gas production was marketed under short-term contracts at spot market prices primarily to TOTAL S.A. Spot market prices for natural gas were on the average lower in 2009 than spot market prices in 2008.

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.

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Below is a summary of Royalty income received on the Trust properties for each of the years ended December 31, 2009, 2008 and 2007:

	2009			2008			2007

Gross proceeds @ 90%	$	390,839		$	1,328,010		$	29,550
Operating expenditures @ 90%		(4,557	)		(22,432	)		(88,649	)
Change in abandonment estimate @ 90%		—			102,658			—
Other proceeds (expenditures) @ 90%		—			112,780			—

Net proceeds (deficit)		386,282			1,521,016			(59,099	)
Increase (decrease) in deficit		—			(1,477,149	)		59,099

Net proceeds after deficit recovery	$	386,282		$	43,867			—

Royalty income (99.99%)(1)	$	430,106		$	—		$	—

(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, 2009, 2008 and 2007:

	Years Ended December 31,

	2009			2008			2007
Royalty income	$	430,106		$	—		$	—
Proceeds from sale of royalty properties		654,660			—			—
Interest income		54			—			5,080
General and administrative expenses		(1,084,820	)		(—	)		(5,080	)

Distributable income	$	—		$	—		$	—

Distributable income per unit	$	—		$	—		$	—
Accumulated deficit (as of period end)	$	(—	)	$	(—	)	$	(1,477,002	)

The Trust had no distributable income in 2009, 2008 and 2007. The reserve for Trust expenses, loans under the Demand Promissory Note with JPMorgan and other advances payable to JPMorgan were used to pay $2,042,072 of the Trust's general and administrative expenses of $2,629,257 for the year ended December 31, 2009 and $270,595 of accrued expenses from 2008. The Trust had unpaid expenses of $75,055 as of December 31, 2009. 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. On September 28, 2007, the Trust entered into a Demand Promissory Note with JPMorgan. This Demand Promissory Note was amended on December 3, 2007, August 25, 2008 and January 12, 2009, in which loans were advanced by the lender from time to time not to exceed $5 million. This Demand Promissory Note was used to pay any unpaid administrative expenses related to the operation of the Trust. As of December 31, 2009, approximately $5,599,718 had been advanced to the Trust by JPMorgan to pay Trust expenses, including $5.0 million under the Demand Promissory Note.

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

	Years Ended December 31,

	2009			2008			2007
General and administrative costs incurred during the year	$	2,629,257		$	1,966,572		$	2,666,727
(Deductions from) additions to reserve for trust expenses		302,095			(2,900	)		(797,075	)
Total expenses paid by JPMorgan during current period		(2,042,072	)		(1,884,032	)		(1,673,617	)
Unpaid trust expenses		(75,055	)		(270,595	)		(190,955	)
Unpaid trust expenses from prior period		270,595			190,955			—

General and administrative costs as reported	$	1,084,820		$	—		$	5,080

General and administrative expenses of the Trust for 2009 increased 34% to $2,629,257 for 2009 as compared to $1,996,569 for 2008. The increase in general and administrative expenses in 2009 is primarily due to an increase in expenditures related to litigation and the Trust's termination. 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 litigation and expenditures related to the anticipated sale of Trust properties pursuant to the Trust's termination.

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

Brazos A-7 and A-39

	2009			2008			2007

Gross proceeds @ 90%	$	39,187		$	124,818		$	29,550
Operating expenditures @ 90%		(4,557	)		(748	)		(60,705	)
Change in abandonment estimate @ 90%		—			—			(373	)
Capital expenditures @ 90%		—			—			—

Net proceeds (deficit)	$	34,630		$	124,070		$	(31,528	)

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, 2009, these two blocks had one well capable of 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 #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 was

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shut in from time to time since then as the operator encountered and addressed hydrogen sulfide issues. The well also produced a carbon dioxide content that exceeds pipeline specifications. This higher content required the operator to mix production at the platform with production from other fields in order to transport the product. Production was routed to the A-52C platform owned by Beryl Oil and Gas. That platform was operated by Arena, which also served 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 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 was producing at approximately 1.4-1.7 MM/D with a gradually declining flowing tubing pressure. There was no assurance regarding the longevity of the gas production on the 52C host platform. Blending with this gas was 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 informed the Trustee that it believed this process was 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 continued to own the undivided one-half interest not burdened by the Partnership's net profits interest and participated in and operated 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 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 Partnership) to payment until drilling costs and applicable interest were recovered, whereas the overriding royalty interest retained under the farmout agreement entitled 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 were born entirely by PNR and Woodside and were not subject to recoupment from any proceeds otherwise payable to the Partnership or the Trust. Similarly, the Partnership's interest in the "Midway" prospect on Brazos A-39 was entitled to payment prior to PNR's and Woodside's recovery of expenses for drilling, completion, sub-sea tie backs and other costs.

The Trustee has been informed that Pioneer expects to commence plugging and abandoning, or other disposition, of the Partnership's remaining property in the Brazos A-39 Block during the first quarter of 2010. Reference is made to "Business—Status of Trust, Timing of Liquidation and Legal Proceedings" contained in Item 1 of this Form 10-K.

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West Delta 61 and Other

	2009		2008			2007

Gross proceeds @ 90%	$	351,652	$	1,203,192		$	—
Operating expenditures @ 90%		—		(21,684	)		(27,944	)
Change in abandonment expenditures @90%		—		102,658			373
Capital expenditures @ 90%		—		112,780			—

Net proceeds (deficit)	$	351,652	$	1,396,946		$	(27,571	)

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 were four wells producing on this block, and their combined rate was 1.2 MMcf/day and 200 barrels of oil per day.

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 were 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. On November 11, 2009, the Partnership's assets in the West Delta 61 Block were sold at auction to the highest bidder, Emerald Energy, with a sales price of $700,000 in accordance with the final judgment and settlement agreement. Reference is made to "Business—Status of Trust, Timing of Liquidation and Legal Proceedings" contained in Item 1 of this Form 10-K.

Capital Expenditures

PNR does not anticipate any future capital expenditures on the Royalty Properties, other than plugging and abandonment costs for which the Trust has no direct liability.

Other Proceeds

During the fourth quarter of 2009, the Trust received $654,660 of net proceeds from the sale of its interest in the West Delta 61 property. 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.

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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	$	—

Balance, December 31, 2009	$	—

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 paid the expenses on behalf of the Trust, but JPMorgan could decline to fund any request of the Trust for borrowings at anytime, for any reason, including the event that JPMorgan had reason to believe that the Trust would not be able to satisfy its obligation to repay the Demand Loans. Interest on the note was calculated at a rate per annum equal to Prime Rate plus two percent (2%), paid annually. The Demand Promissory Note was 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.

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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 was 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 did not exceed $3 million and the loan was 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. 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.

As of December 31, 2009, there was $5.0 million outstanding under the Demand Promissory Note, together with $480,443 of accrued and unpaid interest expense. In addition, there was outstanding $599,718 of additional advances by the Trustee in addition to amounts outstanding under the Demand Promissory Note as well as $75,055 in trust expenses payable. The Demand Promissory Note and interest accrued and unpaid thereunder was canceled on March 24, 2010 pursuant to the Settlement Agreement. Reference is made to "Business—Status of Trust, Timing of Liquidation and Legal Proceedings" contained in Item 1 of this Form 10-K.

Production and Price Review

Production volumes for natural gas decreased to 41,834 Mcf in 2009 as compared with 79,877 Mcf in 2008. The average sales price received for natural gas in 2009 was $4.27 per Mcf as compared with $8.86 per Mcf in 2008. Crude oil, condensate and natural gas liquids production volumes decreased to 4,249 barrels in 2009 as compared to 6,138 barrels in 2008. The average sales price in 2009 for crude oil, condensate and natural gas liquids was $49.92 per barrel as compared with $101 per barrel in 2008.

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.

Off-Balance Sheet Arrangements

None.

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

Not applicable.

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Item 8. Financial Statements and Supplementary Data.

MESA OFFSHORE TRUST

STATEMENTS OF DISTRIBUTABLE INCOME

	Years Ended December 31,

	2009			2008		2007
Royalty income	$	430,106		$	—	$	—
Proceeds from sale of royalty properties		654,660			—		—
Interest income		54			—		5,080
General and administrative expenses		(1,084,820	)		—		(5,080	)

Distributable income	$	—		$	—	$	—

Distributable income per unit	$	—		$	—	$	—

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	December 31,

	2009			2008
ASSETS
Cash and short-term investments	$	302,164		$	69
Net overriding royalty interest in oil and gas properties		380,905,000			380,905,000
Less: accumulated amortization		(380,905,000	)		(380,902,063	)

Total assets	$	302,164		$	3,006

LIABILITIES AND TRUST CORPUS
Reserve for trust expense	$	302,164		$	69
Trust expense payable		75,055			270,595
Interest payable		480,443			230,440
Advances Payable—JPMorgan		599,718			—
Note payable—JPMorgan		5,000,000			3,557,646
Trust Corpus (71,980,216 units of beneficial of interest authorized and outstanding)		(6,155,216	)		(4,055,744	)

Total liabilities and trust corpus	$	302,164		$	3,006

STATEMENTS OF CHANGES IN TRUST CORPUS

	Years Ended December 31,

	2009			2008			2007
Trust corpus, beginning of year	$	(4,055,744	)	$	(1,892,822	)	$	2,937
Trust expenses payable		195,540			(79,640	)		(190,955	)
Interest payable		(250,003	)		(199,253	)		(31,187	)
Advances payable—JPMorgan		(599,718	)		—			—
Note payable—JPMorgan		(1,442,354	)		(1,884,029	)		(1,673,617	)
Amortization of net overriding royalty interest		(2,937	)		—			—

Trust corpus, end of year	$	(6,155,216	)	$	(4,055,744	)	$	(1,892,822	)

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

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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 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 Chase Bank, N.A. 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 $359,000, $181,000 and $177,000 for the years 2009, 2008 and 2007, respectively. As described further in "Status of the Trust, Timing of Liquidation and Legal Proceedings" below, the Termination Threshold was met in the three consecutive years ending December 31, 2004. However, due to litigation involving the Trust that challenged whether the Termination Threshold was in fact 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. The Trustee entered into a Final Settlement Agreement on May 18, 2009. On August 6, 2009, the court responsible for the litigation initially approved the Final Settlement Agreement and issued its Findings of Fact and Conclusions of Law With Respect to Final Settlement Agreement. On September 14, 2009, the court signed its Final Judgment, resolving all parties and all claims in the lawsuit. Pioneer completed the sale of the West Delta 61 properties effective December 1, 2009. The Final Judgment became binding and non-appealable on February 1, 2010. For further descriptions of these matters, see "Status of the Trust, Timing of Liquidation and Legal Proceedings," below.

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MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(1) Trust Organization and Provisions (Continued)

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 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.

Status of the Trust, Timing of Liquidation and Legal Proceedings

Pioneer has informed the Trustee that it expects to commence plugging and abandonment, or other disposition, of the Partnership's remaining property on the Brazos A-39 Block during the first quarter of 2010. The Trustee expects to make a final liquidating distribution as promptly as practicable after such date, if there are any remaining proceeds after all of the Trust's liabilities have been paid by the Trustee.

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(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) an alleged breach of fiduciary duty. The remedies MOSH sought included (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.

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

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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.

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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 was 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 to the Trustee 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 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, but was subsequently shut in again on September 2, 2009, and has been off production ever since. The lease expired 180 days after last production.

Given its conclusion that the Trust was better off with the post-farmout override, and hoping to the end this 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.

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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.

By notice dated February 6, 2009, which the Trustee mailed to all unitholders of record on February 10, 2009, the Trustee announced again 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 to intervene in the Lawsuit. At the public auction on March 18, 2009, no bids were submitted, for the Partnership assets, in the face 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. On April 15, 2009 and May 9, 2009, respectively, unitholders Michael Brown and Benjamin Ginter filed additional interventions (collectively, along with other individuals previously defined as such, the "Individual Intervenors").

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(1) Trust Organization and Provisions (Continued)

and forgive repayment of the existing $5 million Demand Promissory Note (the "Credit Facility") provided by JPMorgan, as lender, to the Trust; and (c) Woodside would pay to the Trust $1 million. Notwithstanding certain other releases, the Trustee will be permitted to use the remaining balance available under the Credit Facility and any other Trust income to pay Trust liabilities and expenses as permitted under the Trust Indenture prior to the final distribution of any net settlement proceeds. These liabilities and expenses include any out-of-pocket costs incurred for effecting the sale of assets in the Liquidation Process and for any other fees and expenses relating to the administration of the Trust after April 27, 2009. As provided in the Final Settlement Agreement, each of the parties agreed to release any and all claims against the other parties that are, or could have been, asserted in the Lawsuit, including any claims for reimbursement of attorneys' fees or costs, except as provided for under the Final Settlement Agreement.

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September 2, 2009 because the production does not meet pipeline specifications. The lease expired 180 days after last production. Based on these events, Pioneer has informed the Trust that it is moving forward with the final accounting relating to the termination, liquidation and wind-up of the Partnership in accordance with the Final Settlement Agreement and the Partnership's First Amended and Restated Articles of General Partnership. Pioneer expects to commence that process by the end of the first quarter 2010.

The Trustee has held in reserve amounts sufficient to cover estimated expenses associated with the winding up and termination of the Trust. Also, in accordance with the Court's Final Judgment, counsel for the Plaintiffs, together with the 2009 Unit Holder Group, have been awarded total attorneys' fees and expenses of $7,750,000, which the Trustee also paid and deducted on March 24, 2010. In addition, JPMorgan made a payment to the Trust in the amount of $5 million, and released all claims for payment and forgave repayment of all obligations (including principal and accrued and unpaid interest thereon) under the existing $5 million Demand Promissory Note in accordance with the terms of the Final Settlement Agreement effective March 24, 2010. Amounts remaining after the completion of the termination of the Trust, if any, will be paid to unitholders as of the February 22, 2010 record date in one or more final liquidating distributions.

The final liquidating 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

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Trust assets and during 2009, the remaining properties in which the Trust had an interest were either sold or were in process of being plugged and abandoned.

During the two years ended December 31, 2009, the Trust incurred general and administrative expenses which exceeded Royalty and interest income and its available cash reserves, due to 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 was 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 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. As of December 31, 2009, there was outstanding $5.0 million under the Demand Promissory Note together with $480,443 of accrued and unpaid interest expense. The Demand Promissory Note was cancelled effective March 24, 2010. In addition, as of December 31, 2009, there was outstanding $599,718 advanced by JPMorgan for payment of Trust expenses and $75,055 in trust expenses payable. The Trust intends to pay the advances and existing unpaid expenses and future expenses in excess of royalty income through the use of proceeds from the Final Settlement Agreement, or from the sale of the Trust's assets.

(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.

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(3) Net Overriding Royalty Interest (Continued)

The Net Overriding Royalty Interest is reviewed for impairment whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. If circumstances require the Net Overriding Royalty Interest to be tested for possible impairment, the Trust first compares undiscounted cash flows expected to be generated by the Net Overriding Royalty Interest to its carrying value. If the carrying value of the Net Overriding Royalty Interest is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. The fair value of the Net Overriding Royalty Interest is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount.

An impairment related to the Net Overriding Royalty was recorded in 2009 as a result of the termination of the Trust and the related sale of the West Delta 61 lot and abandonment of the Brazos A-39 lot. The remaining carrying value of the Net Overriding Royalty of $2,937 was written off. This resulted in a full write down of the asset, which was included in the amortization of royalty interest in the Trust Corpus, as this amount does not affect cash earnings. There was no impairment recorded for the years ended December 31, 2008 and 2007.

(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;

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, general and administrative expenses would be recorded in the month they accrue 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 would require a liquidation basis of accounting.

The preparation of the financial statements requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. The Trust considers all highly liquid investments with a

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(4) Basis of Accounting (Continued)

maturity of three months or less to be cash equivalents. Subsequent events were evaluated through the issuance date of the financial statements.

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 costs incurred. As of December 31, 2007, there was a deficit balance due PNR of approximately $1.5 million which has 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.

During the twelve months ended December 31, 2009, the Trust received $430,106 in Royalty income and $654,660 in proceeds from sale of royalty properties; however, no Royalty income or sales proceeds will be distributed to unitholders until the Trustee recoups Trust expenses being paid from the reserve that the Trustee established for anticipated future general and administrative expenses, loans under a demand promissory note by the Trustee and other advances by the Trustee. As of December 31, 2009, approximately $6,155,216 will be recouped by the Trustee from future Royalty income before liquidating Trust distributions will be made. During the twelve months ended December 31, 2009 and 2008, the Trust had no distributable income. The reserve for Trust expenses and advances under the Demand Promissory Note with JPMorgan were used to pay $2,042,072 of the Trust's general and administrative expenses of $2,629,257 for the year ended December 31, 2009 and $270,595 of accrued expenses from 2008. The Trust had unpaid expenses of $75,055 as of December 31, 2009. 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.

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

	Years Ended December 31,

	2009			2008			2007
General and administrative costs incurred during the year	$	2,629,257		$	1,966,572		$	2,666,727
(Deductions from) additions to reserve for trust expenses		302,095			(2,900	)		(797,075	)
Total expenses paid by JP Morgan during current period		(2,042,072	)		(1,884,032	)		(1,673,617	)
Unpaid Trust expenses		(75,055	)		(270,595	)		(190,955	)
Unpaid Trust expenses from prior period		270,595			190,955			—

General and administrative costs as reported	$	1,084,820		$	—		$	5,080

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(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 paid the expenses on behalf of the Trust, but JPMorgan could decline to fund any request of the Trust for borrowings at anytime, for any reason, including the event that JPMorgan had reason to believe that the Trust would not be able to satisfy its obligation to repay the Demand Loans. Interest on the note was 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 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 was 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 did not exceed $3 million and the loan was 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, 2009 was a Prime Rate of 3.25%, plus 2% for a combined rate of 5.25%.

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(5) JPMorgan Demand Promissory Note (Continued)

As of December 31, 2009, there was outstanding $5,599,718 of principal loaned or advanced for payment of Trust expenses (including $5.0 million under the Demand Promissory Note) together with $480,443 of accrued and unpaid interest expense. At December 31, 2009, the Trust had $0 available under the Demand Promissory Note. No assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at all. As noted above, JPMorgan has no further obligation to advance additional monies to the Trust, and as of December 31, 2009, $5,599,718 together with accrued and unpaid interest on the Demand Promissory Note loans remained payable to JPMorgan.

(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, 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. 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. Bank of New York Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Unitholders whose units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.

(8) Recently Issued Pronouncements

In May 2009, the FASB issued FASB ASC 855, "Subsequent Events," and in February 2010, the FASB issued ASC Update 2010-09, "Subsequent Events (Topic 855)—Amendments to Certain Recognition and Disclosure Requirements," which establishes standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. Under this standard, entities that file or furnish financial statements with the SEC, such as the Trust, are required to use an issued date in evaluating subsequent events. This standard, as updated, is effective February 24, 2010,

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(8) Recently Issued Pronouncements (Continued)

and the Trust adopted it at that date. The adoption did not have a material impact on the Company's results of operations or financial position.

In June 2009, the FASB established the FASB Accounting Standards Codification (Codification), which officially commenced July 1, 2009, to become the source of authoritative US GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative US GAAP for SEC registrants. Generally, the Codification is not expected to change US GAAP. All other accounting literature excluded from the Codification will be considered nonauthoritative. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We adopted the new standards for our quarter ending September 30, 2009. All references to authoritative accounting literature are now referenced in accordance with the Codification.

(9) Supplemental Reserve Information (Unaudited)

Effective for fiscal years ending on or after December 2009, the SEC 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
•: nontraditional resources—the definition of oil and gas producing activities will expand and focus on the marketable product rather than the method of extraction.

The Trust adopted the new requirements effective December 31, 2009. The adoption did not have a material impact on the Trust's distributable income, financial position, proved reserves or future net Royalty income. There were no other significant impacts of adoption.

As of December 31, 2009, the Trust had no producing properties. As disclosed in Note 1, the remaining properties in which the Trust had an interest were either sold during 2009 or are in the process of being plugged and abandoned. As such, the Trust had no proved reserves or future Royalty income as of December 31, 2009.

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

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(9) Supplemental Reserve Information (Unaudited) (Continued)

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.

Reserves for natural gas, and oil and condensate at December 31, 2008, 2007 and 2006, were estimated using year-end prices and existing contract terms. 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 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.

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(9) Supplemental Reserve Information (Unaudited) (Continued)

Estimated Quantities of Proved and Proved Developed Reserves (Unaudited)

		Oil and Condensate			Natural Gas

		(Bbls)			(Mcf)
Proved Reserves:
	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
	Sale of properties		(1,750	)		(148,918	)
	Revisions of previous estimates		(84	)		(23,597	)
	Extensions, discoveries and other additions		—			—
	Production		(4,248	)		(40,784	)

	December 31, 2009		—			—
Proved Developed Reserves:
	December 31, 2006		10,613			360,062
	December 31, 2007		10,391			276,858
	December 31, 2008		6,082			213,299
	December 31, 2009		—			—

(See Notes on following page.)

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

		December 31,

		2009		2008			2007
		(In thousands)
Ninety percent of future gross proceeds		$	—	$	1,494		$	2,900
Less ninety percent of—
	Future operating costs		—		—			—
	Future capital costs, net of amounts previously accrued		—		—			(1,411	)
	Deficit due PNR		—		—			(65	)

Future Royalty income			—		1,494			1,424
Discount at 10% per annum			—		(242	)		(232	)

Standardized measure of future Royalty income from proved oil and gas reserves		$	—	$	1,252		$	1,192

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MESA OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(9) Supplemental Reserve Information (Unaudited) (Continued)

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,

	2009			2008			2007
	(In thousands)
Standardized measure at beginning of year	$	1,252		$	1,192		$	768
Sale of properties(1)		(736	)		—			—
Revisions of previous estimates		(86	)		114			(323	)
Net changes in prices and production costs		—			(173	)		654
Extensions, discoveries and other additions		—			—			—
Changes in estimated future development costs		—			—			16
Royalty income		(430	)		—			—
Accretion of discount		—			119			77

Net changes in standardized measure		(1,252	)		59			424

Standardized measure at end of year	$	—		$	1,252		$	1,192

*: 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.
(1): The Partnership's assets in the West Delta 61 Block were sold at auction with a sales price of $700,000 ($654,660 net of transaction fees) on November 11, 2009.

(10) Selected Quarterly Financial Data (Unaudited)

	Summarized Quarterly Results

	Three Months Ended
	March 31		June 30		September 30		December 31
2009:
Royalty income	$	112,567	$	102,563	$	86,113	$	128,863
Proceeds from sale of Royalty Properties	$	—	$	—	$	—	$	654,660
Distributable income	$	—	$	—	$	—	$	—
Distributable income per unit	$	—	$	—	$	—	$	—
2008:
Royalty income	$	—	$	—	$	—	$	—
Distributable income	$	—	$	—	$	—	$	—
Distributable income per unit	$	—	$	—	$	—	$	—

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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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2009, 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 and during 2009, the remaining properties in which the Trust had an interest were either sold or were in process of being plugged and abandoned. 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. 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.


/s/ KPMG LLP
Houston, Texas March 31, 2010

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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 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, 2009.

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

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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.

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 2009.

Item 11. Executive Compensation.

Not applicable.

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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.

(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 "—Status of the Trust, Timing of Liquidation and Legal Proceedings—Legal Proceedings" 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 paid the expenses on behalf of the Trust, but JPMorgan could decline to fund any request of the Trust for borrowings at anytime, for any reason, including the event that JPMorgan had reason to believe that the Trust would not be able to satisfy its obligation to repay the Demand Loans. Interest on the note was calculated at a rate per annum equal to Prime Rate plus two percent (2%), paid annually. The Demand Promissory Note was 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.

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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 was 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 did not exceed $3 million and the loan was not in default. The amendment also provided that interest expense shall be due and payable on the maturity date.

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 2009 and 2008 and fees billed for other services rendered by KPMG LLP.

		2009		2008

Audit fees(1)		$	245,000	$	235,000
Audit-related fees			—		—
Tax fees(2)			53,000		28,000
All other fees			—		—

	Total fees	$	298,000	$	263,000

(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 2009 related to 2008 tax work and paid in 2008 related to 2007 tax work.

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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		28
Statements of Assets, Liabilities and Trust Corpus		28
Statements of Changes in Trust Corpus		28
Notes to Financial Statements		29
Report of Independent Registered Public Accounting Firm—KPMG LLP		47

(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)



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)

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10(a)*	Final Settlement Agreement, dated May 18, 2009, by and among JP Morgan Chase Bank, N.A., MOSH Holding, L.P., Dagger-Spine Hedgehog Corporation, Pioneer Natural Resources Company, Pioneer Natural Resources Company USA, Inc., and Woodside Energy (USA), Inc. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on May 19, 2009)	1-8432	10.1
10(b)*	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(c)*	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(d)*	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(e)*	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
10(f)*	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
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 in Certain Interests owned by Mesa Offshore Trust (Incorporated by reference to Exhibit 99(a) to Form 10-K filed on March 31, 2009).	1-8432	99(a)

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

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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, 2010	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.

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EXHIBIT INDEX



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)*	Final Settlement Agreement, dated May 18, 2009, by and among JP Morgan Chase Bank, N.A., MOSH Holding, L.P., Dagger-Spine Hedgehog Corporation, Pioneer Natural Resources Company, Pioneer Natural Resources Company USA, Inc., and Woodside Energy (USA), Inc. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on May 19, 2009)	1-8432	10.1
10(b)*	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(c)*	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(d)*	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(e)*	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
10(f)*	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
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 in Certain Interests owned by Mesa Offshore Trust (Incorporated by reference to Exhibit 99(a) to Form 10-K filed on March 31, 2009).	1-8432	99(a)

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

MESA OFFSHORE TRUST 10-K