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 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.

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, formerly a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. (successor to Mesa Operating Co.), a wholly owned subsidiary of Pioneer (“PNR” or “Pioneer”) (collectively, the mergers are referred to herein as the “Merger”). Subsequent to the Merger, Pioneer owns and operates its assets through PNR and is also the managing general partner of the Partnership. As hereinafter used in this report, the term PNR generally refers to the operator of the Royalty Properties, unless otherwise indicated. See “—Legal Proceedings and Status of the Trust” beginning on page 8 of this Form 10-K and “—Timing of Liquidation” beginning on page 12 of this Form 10-K for additional information regarding PNR 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 termination 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 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 paid to the Trustee as compensation were approximately $360,000, $204,000 and $148,000, for the years 2006, 2005 and 2004, respectively. As described further in “—Legal Proceedings and Status of the Trust” beginning on

page 8 of this Form 10-K, the Termination Threshold was met in each of the three consecutive years ending December 31, 2004. Upon termination of the Trust, the Trustee will sell for cash all the assets held in the Trust estate and make a final distribution 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 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” on page 14 of this Form 10-K. 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 there from. PNR, as owner of the working interest in the Royalty Properties, is required to maintain books and records sufficient to determine the amounts payable under the Royalty. Additionally, in the event of a controversy between PNR and any purchaser as to the correct sale price for any production, amounts received by PNR and promptly deposited by it with an escrow agent are not considered as having been received by PNR and therefore are not subject to being payable with respect to the Royalty until the controversy is resolved; but all amounts thereafter paid to PNR by the escrow agent will be considered amounts received from the sale of production. Similarly, operating costs include any amounts PNR is required to pay whether as a refund, interest or penalty to any purchaser because the amount initially received by PNR as the sales price was in excess 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.

The Royalty Properties are required to be operated by PNR in accordance with reasonable and prudent business judgment and good oil and gas field practices. PNR has the right to abandon any well or lease if, in its opinion, such well or lease ceases to produce or is not capable of producing oil, gas or other minerals in commercial quantities. PNR markets the production on terms deemed by it to be the best reasonably obtainable under the circumstances. See “Contracts” on page 24 of this Form 10-K. The Trustee has no power or authority to exercise any control over the operation of the Royalty Properties or the marketing of production there from.

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.

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.

Ownership of Units

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.

Income and Depletion

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

Generally, prior to the Revenue Reconciliation Act of 1990, the transferee of an oil and gas property could not claim percentage depletion with respect to production from the property if it was “proved” at the time of the transfer. This rule is not applicable in the case of transfers of properties after October 11, 1990. Thus, eligible 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. A long-term capital gains rate of 15% applies to most capital assets sold or exchanged with a holding period of more than one year. 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.

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 produced by the Royalty at a rate equal to 30% or, if applicable, at a lower treaty rate. This tax will be withheld by the Trustee and remitted directly to the United States Treasury. A non-U.S. unitholder may elect to treat the income from the Royalty as effectively connected with the conduct of a United States trade or business under provisions of the Code or pursuant to any similar provisions of applicable treaties. Upon making this election a unitholder is entitled to claim all deductions with respect to that income, but he must file a United States federal income tax return to claim these deductions. This election once made is irrevocable unless an applicable treaty allows the election to be made annually.

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 adviser 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 should consult its own tax advisor with respect to the treatment of royalty income.

LEGAL PROCEEDINGS AND STATUS OF THE TRUST

Hurricane Operations Update

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

Status of the Trust

The Trust Indenture provides that the Trust will 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 has taken steps to begin the process of liquidating the Trust. See “—Timing of Liquidation” below in this Item 1. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no discretion regarding the occurrence of the Termination Threshold or its consequences.

but, as is customary, access to information and participation may be limited to persons who execute confidentiality agreements regarding information provided by the working interest owners. The Trustee may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a “public” auction in the sense that it may not be open to anyone who does not satisfy these requirements. The Trustee is currently reviewing a potential online bidding process for participants in order to provide current public information on bidding to the marketplace. The Trustee will also determine a duration of bidding that it deems in the best interest of the Unitholders.

Legal Proceedings

On April 11, 2005, MOSH Holding, L.P. (“MHLP”) filed an Original Petition in the District Court of Travis County, Texas, 250th Judicial District, against Pioneer Natural Resources Company (“PNR”); Pioneer Natural Resources USA, Inc. (together with PNR, “Pioneer”); Woodside Energy (USA), Inc. (“Woodside”); and JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (Case No. GN501113) (the “Lawsuit”). The Lawsuit is currently before the 334th Judicial District of Harris Country, Texas (the “Court”). MHLP’s Original Petition alleges 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 drill 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, MHLP later added claims against the Trustee for (1) an accounting, and (2) breach of fiduciary duty. The remedies MHLP seeks include (a) reconstruing the Trust Indenture to determine that the Trust is 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 MHLP 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.

MHLP’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 voluntarily entered into an agreement with MHLP whereby the Trustee would not terminate the Trust without first giving MHLP at least sixty days written notice. This agreement allowed MHLP time to obtain documents and discovery from Pioneer and Woodside, and allowed the Trustee time to investigate the claims asserted by MHLP against Pioneer and Woodside to determine if they had any merit and, most importantly, whether they 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 MHLP and Pioneer their respective legal analyses of the challenged farmout.

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

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

While the Trustee, Pioneer, and Woodside all agreed to an expedited trial of the farmout issues, MHLP balked. Contrary to the assertions of MHLP and the Intervenor Plaintiffs identified below, the Trustee never agreed that the claims asserted by MHLP against Pioneer and Woodside “had merit” – the Trustee simply stated that the farmout issue might merit adjudication at that time to determine (1) if MHLP was legally correct, and (2) if setting aside the farmout would benefit the Trust.

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

It was at this point, in November 2005, in the midst of the Trustee’s negotiations with MHLP to obtain an agreed adjudication of MHLP’s claims, that MHLP 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, MHLP amended its petition and asserted claims against the Trustee on November 28, 2005.

Although MHLP’s claims against the Trustee were meritless, to avoid any further assertion that the Trustee could not impartially evaluate MHLP’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 MHLP’s motion for a temporary injunction to remove JPMorgan as Trustee and appoint a principal of MHLP, 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, neither MHLP nor Pioneer have identified a willing qualified successor Trustee that is not also a lender under one of Pioneer’s credit facilities (which status MHLP contends is an alleged conflict of interest).

On December 8, 2006, Dagger-Spine Hedgehog Corporation (“Dagger-Spine”) filed a petition to intervene in the Lawsuit as a Plaintiff, alleging claims virtually identical to MHLP. Another group of unitholders, 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 MHLP.

Agreement”). The Trustee filed a motion for approval of the Conditional Settlement Agreement with the Court on January 30, 2007.

The Conditional Settlement Agreement is the product of extensive investigations and negotiations by the Trustee. In 2006, after the Court denied MHLP’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 MHLP and the Intervenors is that Pioneer and Woodside delayed the commencement of production from the well drilled pursuant to the Pioneer-Woodside Farmout – the Midway #5 well on the Brazos A-39 Lease. Woodside and Pioneer witnesses have given 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 this time, the Trustee instructed its independent petroleum reserve engineers to evaluate how the production results and projected production from the well might affect the value of the Trust’s interests. The Trustee’s independent engineers determined that the initial data regarding projected production from the well did not warrant a material change in prior assessments of the value of the Trust’s assets.

Pioneer subsequently reported to the Trustee that production from the well was suspended in July 2006 due to mercury contamination identified at downstream facilities where the production from the well is commingled with production from other wells. An updated evaluation from the Trustee’s independent petroleum reserve engineers estimated that revenues from future production from the well likely would not exceed the costs of drilling and completing the well. Accordingly, 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 MHLP and the Intervenors. The well resumed production in February 2007.

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

Based on the information available to the Trustee and its analysis outlined above, the Trustee believes that the benefits received under the Conditional Settlement Agreement outweigh the potential benefits that may be achieved by the Trust litigating any of the asserted claims against Pioneer and Woodside, which would require the Trust to incur and assume the risk of further significant litigation costs. As a result, the Trustee believes the Conditional Settlement Agreement is in the best interest of the unitholders of the Trust. The Trustee has executed the Conditional Settlement Agreement and is recommending to the Court that the agreement be approved.

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

The Trustee will make the full detail of the underlying data of the December 31, 2006 reserve report available for use in connection with the sale of the Partnership’s Royalty Properties as part of the Trust termination. For more information regarding the estimated remaining life of each of the Royalty Properties, the estimated future net revenues of the Royalty Properties and information relating to farm-outs of interests on the Royalty Properties based on information provided by PNR to D&M, see pages 23 and 24 of this Form 10-K and Note 6 in the Notes to Financial Statements included elsewhere in this Form 10 K. The final distribution to unitholders will be an amount net of funds required to satisfy all Trust liabilities.

TIMING OF LIQUIDATION

The Trust Indenture provides that the Trust will 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. Under the proposed Conditional Settlement Agreement, Pioneer and the Trustee have agreed that Pioneer shall arrange for the sale of all assets of the Partnership as provided for under the Trust Indenture on, or as soon as practical after, July 1, 2007, or on an earlier date as set forth in the proposed settlement. The Trustee filed a motion for approval of the Conditional Settlement Agreement with the court on January 30, 2007. See “Business—Legal Proceedings and Status of the Trust” in Item 1 of this Form 10-K.

Due to the pending litigation, the Trustee cannot predict the timing of the sale of all or a portion of the Trust properties as part of the Trust termination.

Assets and Liabilities in the Process of Liquidation

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

	December 31, 2006
ASSETS
Cash and short term investments		$	797,074
Interest receivable		2,970
Net overriding royalty interest in oil and gas properties		1,475,584
Total assets		2,275,628
LIABILITIES
Reserve for Trust expenses		$	800,044
Total liabilities		800,044
Net assets in process of liquidation		$1,475,584

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

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

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

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

· Discount rate of 10%.

· Future income taxes were not taken into account.

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

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

For more information regarding the estimated remaining life of each of the Royalty Properties, the estimated future net revenues of the Royalty Properties and information relating to farm-outs of interests on the Royalty Properties based on information provided by PNR to D&M, see pages 23 and 24 of this Form 10-K and Note 6 in the Notes to Financial Statements included elsewhere in this Form 10-K. Subject to the terms and approval of a final Conditional Settlement Agreement, the sale of the assets of the Trust estate may include the related rights to abandonment accruals made by PNR. As explained in “Regulation and Prices—Platform Abandonment and Removal” on page 27 of this Form 10-K, PNR can withhold from the Trust a reserve to cover its share of those future abandonment and removal costs; however, no funds have been withheld as of December 31, 2006.

DESCRIPTION OF ROYALTY PROPERTIES

Producing Acreage and Wells as of December 31, 2006

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

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

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

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

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

Reserves

A study of the proved oil and gas reserves attributable to the Partnership as of December 31, 2006, has been made by D&M. The following letter (the “Reserve Report”) summarizes such reserve study. The Reserve Report reflects estimated reserve quantities and future net revenue based upon estimates of the future timing of actual production without regard to when received in cash by the Trust, which differs from the manner in which the Trust recognizes and accounts for its Royalty income. For further information regarding the Net Overriding Royalty Interest, the Basis of Accounting for the Trust and Supplemental Reserve Information, see Notes 2, 3 and 6, respectively, in the Notes to Financial Statements contained in Item 8 of this Form 10-K.

DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244

APPRAISAL REPORT
as of
DECEMBER 31, 2006
on
PROVED RESERVES
of
CERTAIN INTERESTS
owned by
MESA OFFSHORE TRUST
prepared for
JPMORGAN CHASE BANK, N.A.

FOREWORD

Scope of Investigation

This report presents an appraisal, as of December 31, 2006, of the extent and value of the proved crude oil, condensate, and natural gas reserves of royalty interests in certain properties owned by the Mesa Offshore Trust (MOST) located offshore from Louisiana and Texas in the Gulf of Mexico. The Managing General Partner is Pioneer Natural Resources USA Inc. (PNR). This report was prepared at the request of JPMorgan Chase Bank, N.A., (the Trustee), trustee for MOST.

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2006. Net reserves are defined as that portion of the gross reserves attributable to MOST’s interests after deducting royalties and interests owned by others.

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

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

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

such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Authority

This report was authorized by Mr. Mike Ulrich, Vice President, The Bank of New York Trust Company, N.A., as attorney-in-fact for the Trustee.

Source of Information

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

CLASSIFICATION of RESERVES

Petroleum reserves are classified by degree of proof as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs as of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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

Developed—Reserves that are recoverable from existing wells with current operating methods and expenses.

Developed reserves include both producing and nonproducing reserves. Estimates of producing reserves assume recovery by existing wells producing from present completion intervals with normal operating methods and expenses. Developed nonproducing reserves are in reservoirs behind the casing or at minor depths below the producing zone and are considered proved by production from other wells in the field, by successful drill-stem tests, or by core analyses from the particular zones. Nonproducing reserves require only moderate expense to be brought into production.

Undeveloped—Reserves that are recoverable from additional wells yet to be drilled.

Undeveloped reserves are those considered proved for production by reasonable geological interpretation of adequate subsurface control in reservoirs that are producing or proved by other

wells but are not recoverable from existing wells. This classification of reserves requires drilling of additional wells, major deepening of existing wells, or installation of enhanced recovery or other facilities.

Reserves recoverable by enhanced recovery methods, such as injection of external fluids to provide energy not inherent in the reservoirs, may be classified as proved developed or proved undeveloped reserves depending upon the extent to which such enhanced recovery methods are in operation. These reserves are considered to be proved only in cases where a successful fluid-injection program is in operation, a pilot program indicates successful fluid injection, or information is available concerning the successful application of such methods in the same reservoir and it is reasonably certain that the program will be implemented.

ESTIMATION of RESERVES

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

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

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

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

The rates used for future oil, condensate, and gas production are estimated to be within the capacity of a well or reservoir to produce. Data available from wells drilled on the appraised properties through December 31, 2006, were used to prepare the estimates shown herein. Gross production through December 31, 2006, was deducted from the gross ultimate recovery to arrive at estimates of gross reserves. Production from the West Delta Block 61 field was halted in the third quarter of 2005 as a result of Hurricane Katrina and production is expected to resume in August 2007. The Brazos Block A-7 field ceased production in June 2006 and the lease expired during December 2006. According to PNR, there are no further plans for this lease.

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

Estimates of the gross and net proved reserves, as of December 31, 2006, of the properties appraised are presented as follows. Oil and condensate reserves are expressed in barrels (bbl) and gas reserves are expressed in thousands of cubic feet (Mcf).

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

VALUATION of RESERVES

This report has been prepared using initial prices provided by the Trustee and initial costs provided by PNR on behalf of the Trustee. Future prices were estimated using guidelines established by the United States Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB). In this report, values for proved reserves were based on projections of estimated future production and revenue prepared for these properties.

Oil and Condensate Prices

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

Natural Gas Prices

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

Operating Expenses and Capital Costs

The properties appraised are royalties. Therefore, no operating expenses are incurred. The capital costs included at the request of the Trustee are plugging, abandonment, and decommissioning costs related to facilities of prior producing properties.

The estimated future revenue to be derived from the production and sale of MOST’s net proved reserves, as of December 31, 2006, under the economic assumptions furnished by the Trustee is summarized as follows, expressed in dollars ($):

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

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

The appendix bound with this report presents tabulations and projections of revenue from the proved reserves for the interests appraised.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 10—13, 15

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

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

SUMMARY and CONCLUSIONS

Evaluated herein are royalty interests in certain properties owned by MOST located offshore from Louisiana and Texas in the Gulf of Mexico. Estimates of MOST’s net proved reserves, as of December 31, 2006, of the properties appraised are presented as follows. Oil and condensate reserves are expressed in barrels (bbl) and gas reserves are expressed in thousands of cubic feet (Mcf).

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

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

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

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

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

	Submitted,

	DeGOLYER and MacNAUGHTON
SIGNED: April 10, 2006

	Paul J. Szatkowski, P.E.
	Senor Vice President
	DeGolyer and MacNaughton

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

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

Moreover, the discounted present values in the Reserve Report should not be construed as the current market value of the estimated gas and oil reserves attributable to the Royalty Properties or the costs that would be incurred to obtain equivalent reserves, since a market value determination would include many additional factors. In accordance with applicable regulations of the SEC, estimated future net revenues were based, generally, on current prices and costs, whereas actual future prices and costs may be materially greater or less. The estimates in the Reserve Report use market prices as of December 31, 2006. These prices (having weighted average year end prices of $57.62 to $61.05 per barrel of oil and condensate and $5.42 to $5.64 per Mcf of natural gas as of December 31, 2006) were held constant over the estimated life of the Royalty Properties. These prices were influenced by seasonal demand for natural gas and may not be the most appropriate or representative prices to use for estimating future revenues or related reserve data. The average price of natural gas sold from the Royalty Properties during 2006 was $7.65 per Mcf, representing a combination of contract prices and spot market prices, while the average price of crude oil, condensate and natural gas liquids was $58.64 per barrel.

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

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

Property	Productive Life(1)(2)
West Delta 61		8 years
Brazos A-39		5 years

(1) The Trust will terminate in the event the total amount of cash received per year by the Trust falls below certain levels. Accordingly, it would be possible for the Trust to terminate even though some of the Royalty Properties continued to have remaining productive lives. See “Business—Legal Proceedings and Status of the Trust” on page 8 of this Form 10-K and see “Business—Timing of Liquidation” on page 12 of this Form 10-K.

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

The future net revenues contained in the Reserve Report have not been reduced for future general and administrative costs and expenses of the Trust, which are expected to approximate $1,200,000 annually.

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

CONTRACTS

General

PNR has advised the Trust that during 2006 its offshore gas production was marketed under short-term contracts at spot market prices primarily to TOTAL S.A. PNR has further advised the Trust that it expects to continue to market its production under short-term contracts for the foreseeable future. Spot market prices for natural gas in 2006 were generally higher than spot market prices in 2005.

Market for Natural Gas

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

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

Competition

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

Marketing of Liquids

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

REGULATION AND PRICES

General

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

Operating Hazards and Uninsured Risks

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

FERC Regulation

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

State and Other Regulation

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

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

which may increase the stringency of the standards or expand the applicability of the standards to facilities not currently covered.

Environmental

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

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

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

Platform Abandonment and Removal

PNR is responsible for the abandonment and removal of its offshore drilling and production structures within one year after the cessation of production, although extensions can be requested. PNR can withhold from the Trust a reserve to cover its share of those future abandonment and removal costs; however, no funds have been withheld as of December 31, 2006. See Item 7 of this Form 10-K and Note 3 in the Notes to Financial Statements for amounts withheld as of December 31, 2006 and amounts to be withheld in the future.

Item 1A. Risk Factors.

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

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

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

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

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

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

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

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

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

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

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

· the assumed effect of governmental regulation;

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

· the availability of enhanced recovery techniques; and

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

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

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

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

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

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

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

There are operational risks and hazards associated with the production and transportation of natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of natural gas, releases of other hazardous materials, mechanical failures, cratering and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment of natural resources, or cleanup obligations. The occurrence of drilling, production or transportation accidents at any of the Royalty Properties will reduce Trust distributions by the amount of uninsured costs. These occurrences include blowouts, cratering, explosions and other environmental damage. Offshore activities are also subject to a variety of operating risks such as hurricanes and other weather disturbances. These accidents and other natural disasters may result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any uninsured costs would be deducted as a production cost in calculating net proceeds payable to the Trust.

Terrorism and continued hostilities in the Middle East could decrease Trust distributions or the market price of the units of beneficial interest of the Trust.

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

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

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

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

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

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

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

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

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

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

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

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

The Royalty will be sold and the Trust is being terminated.

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

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

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

PART II

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

The units of beneficial interest of the Trust were delisted from the Pacific Exchange effective May 18, 2001. The Trust units are currently eligible for trading on the OTC Bulletin Board under ticker symbol MOSH.OB. In 2006, the Trust had gross Royalty income of $145,642. However, no Royalty income will be distributed to the unitholders until the Trustee recoups Trust expenses being paid from the reserve that the Trustee has established for anticipated future expenses. The high and low sales prices and distributions per unit for each quarter in the two years ended December 31, 2006 were as follows:

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

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

Item 6. Selected Financial Data.

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

(i) 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.

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 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.

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.

Status of the Trust

The Trust Indenture provides that the Trust will 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 has taken steps to begin the process of liquidating the Trust. See “Business—Timing of Liquidation” below in Item 1 of this Form 10-K. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no discretion regarding the occurrence of the Termination Threshold or its consequences.

without any financing conditions. Accordingly, the auction may not be a “public” auction in the sense that it may not be open to anyone who does not satisfy these requirements. The Trustee is currently reviewing a potential online bidding process for participants in order to provide current public information on bidding to the marketplace. The Trustee will also determine a duration of bidding that it deems in the best interest of the Unitholders.

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

Properties producing as of December 31, 2006

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

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

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

Properties abandoned or scheduled for abandonment as of December 31, 2006

Property				Status
Brazos A-7				Abandoned in 2005 (Newfield platform to be abandoned in 2007)
Brazos A-39				Plug and abandonment procedures completed in 2005 (excluding Midway prospect)*
West Delta 62				Plug and abandonment procedures completed in 2003
South Marsh Island 155				Plug and abandonment procedures completed in 2002
South Marsh Island 156				Plug and abandonment procedures completed in 2002
Vermillion 381				Plug and abandonment procedures completed in 1989
South Pelto 12				Plug and abandonment procedures completed in 1986
Matagorda Island 624				Plug and abandonment procedures completed in 2003
High Island 567				Plug and abandonment procedures completed in 1992

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

Financial and Operational Review

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

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

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

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

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

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

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

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

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

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

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

Brazos A-7 and A-39

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

The Brazos A-7 and A-39 blocks continued to experience a decrease in natural gas production due to natural production decline. As of December 31, 2006, these two blocks had one well capable of producing, the Brazos A-39 # 5. The Brazos A-7 No. B-1 well, operated by Newfield, is no longer producing as of December 31, 2006. PNR entered into farmout agreements 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, 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, has informed the Trustee that the lower horizon of the prospect was determined to be non-commercial, while the middle horizon in the Big Hum 4 sand produced at 10,000 Mcf of gas per day during a seventeen hour flow test. This well came on line April 20, 2006. However, this well has been shut in from time to time since then as the operator has encountered and addressed hydrogen sulfide issues. The well has also produced a carbon dioxide content that exceeds pipeline specifications. This higher content requires the operator to mix production at the platform with production from other fields in order to transport the product. Production is being routed to the A-52C platform owned by Coldren Resources LP. That platform is being operated by Arena, which is also serving as the contract operator for the Midway property. The well was shut in July 21, 2006 by Williams Pipeline due to reported detection of mercury in the gas stream. Following the installation of vessels with mercury absorbing media and negotiation of the required agreements with the owner and operator of the Brazos A-52C host platform, the well was returned to production on February 13, 2007. The current production rate is 2.5 – 3.2 MMCFD with 5,000 psi flowing tubing pressure. The following tubing pressure continues to gradually decline.

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

PNR continues to own the undivided one-half interest not burdened by the Partnership’s net profits interest and will participate in and operate the well as owner of that undivided one-half interest (subject to

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

PNR has noted to the Trustee that the Farmout Agreement 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 entitles the Trust (through the Partnership) to payments prior to the recoupment of expenses incurred by Woodside and PNR. As noted above, the first prospect on Brazos A-7 was determined to be a dry hole. Under the Farmout Agreement and related agreements, those drilling and abandonment costs have been born entirely by PNR and Woodside and are not subject to recoupment from any proceeds otherwise payable to the Partnership or the Trust. Similarly, the Partnership’s current interest in the “Midway” prospect on Brazos A-39 will be entitled to payment prior to PNR’s and Woodside’s recovery of expenses for drilling, completion, sub-sea tie backs and other costs.

West Delta 61 and Other

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

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

The PNR-operated wells ceased production in 2002, and the wells were plugged and abandoned by year-end with the facilities being completely abandoned during 2003. The only remaining wells on this block are in West Delta 61. PNR farmed out a portion of West Delta 61 to Stone Energy retaining a 12.5% (11.25% net to the Trust through the Partnership) overriding royalty interest.

Capital Expenditures

In 2005, the Trust received, from PNR, net proceeds of $375,300 related to the sale of the South Marsh Island 155 platform that was abandoned by PNR and for casings related to the PNR platform at Brazos A-39. PNR does not anticipate any significant capital expenditures on the Royalty Properties in the future. Due to the limited financial capacity of the Trust, PNR has advised that it intends to farm out the Partnership’s interest in the blocks it believes may be produced economically, retaining an overriding royalty interest for the Partnership.

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, 2003:

Balance, January 1, 2003	$	5,640,443
Abandonment cost incurred (Mat. Is. 624 & WD 62)	(2,839,800		)
Balance, December 31, 2003	2,800,643
Abandonment cost incurred (Mat. Is. 624 & WD 62)	(124,492		)
Balance, December 31, 2004	$	2,676,151
Abandonment cost incurred (Brazos A-7A, A-7#4,A-39A1A,A-2 and A-3A)	(2,328,085		)
Balance, December 31, 2005	$	348,066
Abandonment cost incurred (Brazos A-7#4,A-39A1A,A-2 and A-3A Matagorda Island 624, South Marsh Island 155)	(348,066		)
Balance, December 31, 2006	$	—

During the first nine months of 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 December 31, 2006, PNR has spent approximately $867,000 of the $1.4 million estimate, while approximately $533,000 of PNR’s original estimate for total repairs remains to be spent. As the reserve for future abandonment cost was fully utilized during the year, the total $1.4 million of the Partnership’s interest in estimated repairs will be deducted from any 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 Partnership’s portion of abandonment expenses from gross proceeds.

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.

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

Production and Price Review

Production volumes for natural gas decreased to 28,517 Mcf in 2006 as compared with 209,697 Mcf in 2005. The average sales price received for natural gas in 2006 was $7.65 per Mcf as compared with $7.01 per Mcf in 2005. Crude oil, condensate and natural gas liquids production volumes decreased to 359 barrels in 2006 as compared to 12,313 barrels in 2005. The average sales price in 2006 for crude oil, condensate and natural gas liquids was $58.64 per barrel as compared with $48.97 per barrel in 2005.

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

Off-Balance Sheet Arrangements

None.

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

Not applicable.

Item 8. Financial Statements and Supplementary Data.

MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME

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

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

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

STATEMENTS OF CHANGES IN TRUST CORPUS

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

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

MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS

(1) Trust Organization and Provisions

The Trust

The Mesa Offshore Trust (the “Trust”) was created effective December 1, 1982. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership, which was predecessor to MESA Inc., transferred to the Trust a 99.99% interest in the Mesa Offshore Royalty Partnership (the “Partnership”). The Trust is an independent trust administered by JPMorgan Chase Bank, N.A., as trustee (the “Trustee”). JPMorgan Chase Bank, N.A., was formerly known as The Chase Manhattan Bank and is the successor or “JPMorgan” by mergers to the original name of the Trustee, Texas Commerce Bank National Association.

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 $360,000, $204,000 and $148,000 for the years 2006, 2005 and 2004, respectively. As described further in “Business—Legal Proceedings and Status of the Trust” below, the Termination Threshold was met in the three consecutive years ending December 31, 2004. Upon termination of the Trust, the Trustee will sell for cash all the assets held in the Trust estate and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied.

The Partnership

The Partnership was created to receive and hold a net overriding royalty interest (the “Royalty”) in ten producing and non-producing oil and gas properties located in federal waters offshore Louisiana and Texas (the “Royalty Properties”). MESA Inc. created the Royalty out of its working interest in the Royalty Properties and transferred it to the Partnership. Until August 7, 1997, MESA Inc. owned and operated its assets through Mesa Operating Co. (“Mesa”), the operator and the managing general partner of the Royalty Properties. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company (“Pioneer”), formerly a wholly owned subsidiary of MESA, Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. (successor to Mesa), a wholly owned subsidiary of Pioneer (“PNR”) (collectively, the mergers are referred to herein as the “Merger”). Subsequent to the Merger, Pioneer owns and operates its assets through PNR and is also the managing general partner of the Partnership.

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

Legal Proceedings and Status of the Trust

The Trust Indenture provides that the Trust will 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. During 2005, the Trustee has taken steps to begin the process of liquidating the Trust. See “Business—Timing of Liquidation” below in this Note. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no discretion regarding the occurrence of the Termination Threshold or its consequences.

The Trust Indenture provides the Trustee a two-year period during which it must sell all of the Trust properties. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee expects that the sale process will be open to any persons desiring to participate, but, as is customary, access to information and participation may be limited to persons who execute confidentiality agreements regarding information provided by the working interest owners. The Trustee may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a “public” auction in the sense that it may not be open to anyone who does not satisfy these requirements. The Trustee is currently reviewing a potential online bidding process for participants in order to provide current public information on bidding to the marketplace. The Trustee will also determine a duration of bidding that it deems in the best interest of the Unitholders.

On April 11, 2005, MOSH Holding, L.P. (“MHLP”) filed an Original Petition in the District Court of Travis County, Texas, 250th Judicial District, against Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc. (referred to below in this Note collectively with Pioneer Natural Resources Company, as “Pioneer”); Woodside Energy (USA), Inc. (“Woodside”); and JPMorgan, as Trustee of the Mesa Offshore Trust (Case No. GN501113) (the “Lawsuit”). The Lawsuit is currently before the 334th Judicial District of Harris Country, Texas (the “Court”). MHLP’s Original Petition alleges 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 drill 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, MHLP later added claims against the Trustee for (1) an accounting, and (2) breach of fiduciary duty. The remedies MHLP seeks include (a) reconstruing the Trust Indenture to determine that the Trust is 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 MHLP 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.

Throughout 2005, the parties also anticipated that the Midway #5 well on the Brazos A-39 Lease that is the primary subject of the Lawsuit would go into production. Given the vast discrepancy between the reserves claimed by the MHLP 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 MHLP seeks to restore through the Lawsuit. Unfortunately, Hurricane Katrina struck the Gulf of Mexico in August 2005 and delayed the commencement of production until 2006.

While the Trustee, Pioneer, and Woodside all agreed to an expedited trial of the farmout issues, MHLP balked. Contrary to the assertions of MHLP and the Intervenor Plaintiffs identified below, the Trustee never agreed that the claims asserted by MHLP against Pioneer and Woodside “had merit”—the Trustee simply stated that the farmout issue might merit adjudication at that time to determine (1) if MHLP was legally correct, and (2) if setting aside the farmout would benefit the Trust.

precluded, by holding the position of Trustee, from pursuing commercial banking activities not involving Trust funds, MHLP amended its petition and asserted claims against the Trustee on November 28, 2005.

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

The Conditional Settlement Agreement is the product of extensive investigations and negotiations by the Trustee. In 2006, after the Court denied MHLP’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 MHLP and the Intervenors is that Pioneer and Woodside delayed the commencement of production from the well drilled pursuant to the Pioneer-Woodside Farmout—the Midway #5 well on the Brazos A-39 Lease. Woodside and Pioneer witnesses have given 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 this time, the Trustee instructed its independent petroleum reserve engineers to evaluate how the production results and projected production from the well might affect the value of the Trust’s interests. The Trustee’s independent engineers determined that the initial data regarding projected production from the well did not warrant a material change in prior assessments of the value of the Trust’s assets.

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

The Conditional Settlement Agreement is subject to certain conditions, including approval by the Court. The Court has currently scheduled a hearing on the approval for May 21, 2007. MHLP and the Intervenors are not signatories or parties to the settlement and they, or other unitholders of the Trust, may comment or object to the settlement. The settlement is not final until approved by the Court. If the Court approves the proposed settlement, it will enter an order that approves the settlement and dismisses the Lawsuit with prejudice as to all claims that may be brought on behalf of the Trust, either by the Trustee or by unitholders seeking to assert claims on behalf of themselves or the Trust, against Pioneer and Woodside based on the facts asserted in the Lawsuit.

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

Timing of Liquidation

The Trust Indenture provides that the Trust will 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. Under the proposed Conditional Settlement Agreement, Pioneer and the Trustee have agreed that Pioneer shall arrange for the sale of all assets of the Partnership as provided for under the Trust Indenture on, or as soon as practical after, July 1, 2007, or on an earlier date as set forth in the proposed settlement. The Trustee filed a motion for approval of the Conditional Settlement Agreement with the court on January 30, 2007.

Due to the pending litigation, the Trustee cannot predict the timing of the sale of all or a portion of the Trust properties as part of the Trust Termination.

(2) 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.

(3) Basis of Accounting

The financial statements of the Trust 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;

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

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 production 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.

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. For the twelve months ending December 31, 2004, operating and capital costs incurred exceeded proceeds from oil and gas sales; accordingly, no Royalty income was reported.

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

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

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

(4) 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.

(5) 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.

(6) Supplemental Reserve Information (Unaudited)

Estimates of the proved oil and gas reserves attributable to the Royalty as of December 31, 2006 and 2005, are based on a report prepared by DeGolyer and MacNaughton (“D&M”). The 2004 report is based on a report prepared by PNR. The estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission (the “SEC”). Accordingly, the estimates were based on existing economic and operating conditions. The reserve volumes and revenue values contained in the reserve report for the Partnership interest were estimated by allocating to the Partnership a portion of the estimated combined net reserve volumes of the Royalty Properties based on future net revenue. Production volumes are allocated based on royalty income. Because the net reserve volumes attributable to the Partnership interest are estimated using an allocation of reserve volumes based on estimates of future net revenue, a change in prices or costs will result in changes in the estimated net reserve volumes. Therefore, the estimated net reserve volumes attributable to the Partnership interest will vary if different future price and cost assumptions are used. Only costs necessary to develop and produce existing proved reserve volumes were assumed in the allocation of reserve volumes to the Royalty.

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

There are numerous uncertainties inherent in estimating the quantities and value of proved reserves and in projecting the future rates of production and timing of expenditures. The reserve data below

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

Estimates of reserve volumes attributable to the Royalty are shown in order to comply with requirements of the SEC. There is no precise method of allocating estimates of physical quantities of 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 $500,000 annually. The general and administrative expenses of the Trust may increase for the remaining duration of the Trust, depending on the amount of royalty income, increases in accounting, engineering, legal, and other professional fees and other factors.

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

Estimated Quantities of Proved and Proved Developed Reserves (Unaudited)

	Oil and Condensate			Natural Gas
	(Bbls)			(Mcf)
Proved Reserves:
December 31, 2003		11,111		432,679
Revisions of previous estimates		(5,151	)	(258,169	)
Extensions, discoveries and other additions		—		—
Production		—		—
December 31, 2004		5,960		174,510
Revisions of previous estimates		16,613		326,093
Extensions, discoveries and other additions		507		169,150
Production		(12,314	)	(209,698	)
December 31, 2005		10,766		460,055
Revisions of previous estimates		206		(71,476	)
Extensions, discoveries and other additions		—		—
Production		(359	)	(28,517	)
December 31, 2006		10,613		360,062
Proved Developed Reserves:
December 31, 2003.		11,111		432,679
December 31, 2004.		5,960		174,510
December 31, 2005.		10,766		460,055
December 31, 2006.		10,613		360,062

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

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

· 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.

(7) Selected Quarterly Financial Data (Unaudited)

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

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 Pioneer, as the managing general partner of the Partnership, and the working interest owners to JPMorgan Chase Bank, N.A., 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 Trustee carried out an evaluation of the Trust’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the 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, 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 “—Trust unitholders and the Trustee have no control the operation or development of the Royalty Properties and have little influence over operation or development” and “—The Trustee relies upon the working interest owners and managing general partner for information regarding the Royalty Properties” in this Form 10-K for a description of certain risks relating to these arrangements and reliance.

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

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 2006.

Item 11. Executive Compensation.

Not applicable.

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

(a) Security Ownership of Certain Beneficial Owners.

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

(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 (Amend 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 (“MHLP”). MOSH Holding I, L.L.C., a Texas limited liability company (“MOSHLLC”) is the sole general partner of MHLP 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 “—Legal Proceedings and Status of the Trust” and “—Timing of Liquidation” for a description of legal proceedings and related transactions among the Trustee, the Trust and certain unitholders of the Trust.

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 2006 and 2005 and fees billed for other services rendered by KPMG LLP.

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

(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 2006 related to 2005 tax work and paid in 2005 related to 2004 tax work.

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

(a)(2) Schedules

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

(a)(3) Exhibits

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

		SEC File or Registration Number		Exhibit Number
4(a)	*Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982		2-79673		10	(gg)
4(b)	*Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty Partnership, dated December 15, 1982		2-79673		10	(hh)
4(c)	*Partnership Agreement between Mesa Offshore Management Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982		2-79673		10	(ii)
4(d)	*Amendment to Partnership Agreement between Mesa Offshore Management Co., Texas Commerce Bank National Association, as Trustee, and Mesa Operating Limited Partnership, dated December 27, 1985 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of Mesa Offshore Trust)		1-8432		4	(d)
4(e)	*Amendment to Partnership Agreement between Texas Commerce Bank National Association, as Trustee, and Mesa Operating dated as of January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December 31, 1993 of Mesa Offshore Trust)		1-8432		4	(e)
10.1	*Mutual Release and Settlement Agreement dated January 26, 2007 (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 31, 2007)		1-8432		10.1
31	Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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
	By:	/s/ MIKE ULRICH
		Mike Ulrich
		Vice President & Trust Officer
April 16, 2007		The Bank of New York 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.

(Mark One)
x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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

Date: April 16, 2007		/s/ MIKE ULRICH
		Mike Ulrich,
		*Vice President*
		The Bank of New York Trust Company, N.A., as attorney-in-fact for the Trustee

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

		Page
	PART I
Item 1.	Business		4
	Description of the Trust		4
	Description of the Units		6
	Legal Proceedings and Status of the Trust		8
	Timing of Liquidation		12
	Description of Royalty Properties		14
	Contracts		24
	Regulation and Prices		25
Item 1A.	Risk Factors		27
Item 1B.	Unresolved Staff Comments		31
Item 2.	Properties		31
Item 3.	Legal Proceedings		31
Item 4.	Submission of Matters to a Vote of Security Holders		31
	PART II
Item 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		32
Item 6.	Selected Financial Data		32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		39
Item 8.	Financial Statements and Supplementary Data		39
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		50
Item 9A.	Controls and Procedures		50
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		51
Item 11.	Executive Compensation		51
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		51
Item 13.	Certain Relationships and Related Transactions, and Director Independence		52
Item 14.	Principal Accounting Fees and Services		52
	PART IV
Item 15.	Exhibits, Financial Statement Schedules		52
SIGNATURES			54

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

		JPMORGAN CHASE BANK, N.A.
		Trustee for Mesa Offshore Trust
		By:		/s/ MIKE ULRICH
				Mike Ulrich
				Vice President
				The Bank of New York Trust Company, N.A., as attorney-in-fact for the Trustee