Use these links to rapidly review the documentTABLE OF CONTENTS Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.



UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-K/A
Amendment No. 1

|(Mark One)                                                       |                                                                                         
|---------------------------------------------------------------- | ----------------------------------------------------------------------------------------
|ý                                                                | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934    
|FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007                     
|o                                                                | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|FOR THE TRANSITION PERIOD
FROM                                TO

Commission file number 1-8432

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

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

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

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

Title of Each Class

Name of Each Exchange On Which RegisteredNone

None


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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ý No o

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

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

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

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

The aggregate market value of 71,980,216 Units of Beneficial Interest in Mesa Offshore Trust held by non-affiliates of the registrant at the closing
sales price on June 30, 2007, of $0.09 was approximately $6,478,219.

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

As
of March 31, 2008, 71,980,216 Units of Beneficial Interest were outstanding in Mesa Offshore Trust.

DOCUMENTS
INCORPORATED BY REFERENCE:None.



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TABLE OF CONTENTS



|           |  |                                                                                                                 |  | Page
|---------- |  | --------------------------------------------------------------------------------------------------------------- |  | ----
|PART I    
|Item 1.    |  | Business                                                                                                        |  | 4   
|Item 1A.   |  | Risk Factors                                                                                                    |  | 19  
|Item 1B.   |  | Unresolved Staff Comments                                                                                       |  | 24  
|Item 2.    |  | Properties                                                                                                      |  | 24  
|Item 3.    |  | Legal Proceedings                                                                                               |  | 24  
|Item 4.    |  | Submission of Matters to a Vote of Security Holders                                                             |  | 24  
|PART II   
|Item 5.    |  | Market for the Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities |  | 25  
|Item 6.    |  | Selected Financial Data                                                                                         |  | 25  
|Item 7.    |  | Management's Discussion and Analysis of Financial Condition and Results of Operations                           |  | 25  
|Item 7A.   |  | Quantitative and Qualitative Disclosures About Market Risk                                                      |  | 32  
|Item 8.    |  | Financial Statements and Supplementary Data                                                                     |  | 33  
|Item 9.    |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                            |  | 46  
|Item 9A.   |  | Controls and Procedures                                                                                         |  | 46  
|PART III  
|Item 10.   |  | Directors, Executive Officers and Corporate Governance                                                          |  | 48  
|Item 11.   |  | Executive Compensation                                                                                          |  | 48  
|Item 12.   |  | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters                   |  | 48  
|Item 13.   |  | Certain Relationships and Related Transactions, and Director Independence                                       |  | 49  
|Item 14.   |  | Principal Accounting Fees and Services                                                                          |  | 49  
|PART IV   
|Item 15.   |  | Exhibits, Financial Statement Schedules                                                                         |  | 51  
|SIGNATURES |  | 53                                                                                                             

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EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A amends the Registrant's Annual Report on Form 10-K, as filed by the Registrant with the Securities and Exchange Commission on
April 3, 2008, and is being filed solely: (1) to correct the amount of future general and administrative costs and expenses on pages 16 and 42 to $2,500,000 as described elsewhere in the Form 10-K,
and (2) to correct the oil and gas spot prices in effect at December 31, 2007 used to calculate future royalty income on page 27 to $92.52 to $92.63 per barrel.

Note Regarding Forward-Looking Statements

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

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PART I

Item 1.    Business.

DESCRIPTION OF THE TRUST

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

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

The
principal asset of the Trust consists of a 99.99% interest in the Mesa Offshore Royalty Partnership (the "Partnership"). The Trust was created on December 28, 1982, effective
December 1, 1982, when Mesa Petroleum Co. conveyed to the Partnership certain overriding royalty interests (collectively, the
"Royalty") carved out of Mesa Petroleum Co.'s existing working interests in ten producing and non-producing oil and gas leases offshore Louisiana and Texas (the "Royalty
Properties"). The Partnership was formed for the purpose of receiving and holding the Royalty, receiving the proceeds from the Royalty, paying the liabilities and expenses of the Partnership and
disbursing remaining revenues to the Trustee and Mesa Offshore Management Co., the managing general partner of the Partnership at that time, in accordance with their interests. Until
August 7, 1997, MESA Inc. owned and operated its assets through Mesa Operating Co. ("Mesa"), the operator and the managing general partner of the Royalty Properties. On
August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("PNRC"), formerly a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum
Company merged with and into Pioneer Natural Resources USA, Inc. ("PNR") (successor to Mesa Operating Co.), a wholly owned subsidiary of PNRC (collectively, the mergers are referred to
herein as the "Merger"). Subsequent to the Merger, PNR owns and operates its assets through PNRC and is also the managing general partner of the Partnership. PNR and PNRC are referred to hereinafter
collectively as "Pioneer." As hereinafter used in this report, the term PNR generally refers to the operator of the Royalty Properties, unless otherwise indicated. See "Legal Proceedings
and Status of the Trust" beginning on page 9 of this Form 10-K and "Timing of Liquidation" beginning on page 12 of this Form 10-K for
additional information regarding Pioneer and the Trust.

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

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

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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. Amounts paid to the Trustee as compensation were approximately
$177,000, $360,000 and $204,000 for the years 2007, 2006 and 2005, respectively. As described further in "Legal Proceedings and Status of the Trust" beginning on page 9 of this
Form 10-K, the Termination Threshold was met in each of the three consecutive years ending December 31, 2004. However, due to pending litigation involving the Trust that
directly challenges whether the Termination Threshold has in fact been met, the Trustee cannot predict the timing of the sale of all or a portion of the Partnership assets as part of the Trust
liquidation and termination. As part of the liquidation and eventual termination of the Trust, the Trustee will sell for cash all the assets held by the Partnership and make a final distribution to
unitholders of any funds remaining after all Trust liabilities have been satisfied.

The
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 therefrom. PNR, as owner of
the working interest in the Royalty Properties, is required to maintain books and records sufficient to determine the amounts payable under the Royalty. Additionally, in the event of a controversy
between PNR and any purchaser as to the correct sale price for any production, amounts received by PNR and promptly deposited by it with an escrow agent are not considered as having been received by
PNR and therefore are not subject to being payable with respect to the Royalty until the controversy is resolved; but all amounts thereafter paid to PNR by the escrow agent will be considered amounts
received from the sale of production. Similarly, operating costs include any amounts PNR is required to pay whether as a refund, interest or penalty to any purchaser because the amount initially
received by PNR as the sales price was in excess 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 16 of this Form 10-K.

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The
Trustee has no power or authority to exercise any control over the operation of the Royalty Properties or the marketing of production therefrom.

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

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

DESCRIPTION OF THE UNITS

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

Distributions

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

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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.



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.



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.



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.



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

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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.



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.



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.



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

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LEGAL PROCEEDINGS AND STATUS OF THE TRUST



Hurricane Katrina struck the Gulf of Mexico in August 2005. 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 production at West Delta resumed at three of the four wells
in October 2007 at a combined production rate of 4.8 MMCFD.



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

The
Trust Indenture provides the Trustee a two-year period during which it must sell all of the assets of the Partnership. 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.



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 PNRC; PNR; Woodside Energy (USA), Inc. ("Woodside"); and JPMorgan, as Trustee of the Mesa Offshore Trust (Case No. GN501113) (the "Lawsuit"). The Lawsuit is currently
before the 334th Judicial District of Harris Country, Texas (the "Court"). 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 drilled thereon,
(3) fraudulent accounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aiding and abetting breach of fiduciary duty by Woodside, (6) misapplication of
Trust property by Pioneer, (7) conspiracy to misapply fiduciary property by Woodside and Pioneer, (8) common law fraud by Pioneer, (9) gross negligence by Pioneer, and
(10) breach of the conveyance agreement by Pioneer. As described below, 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

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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 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.

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 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.

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 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 damage 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.

10

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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 has 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. MHLP and the Intervenors are referred to hereinafter as the "Plaintiffs."

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 the Plaintiffs. The well
resumed production in February 2007. The well was shut in again on April 18, 2007 due to an increase in hydrogen sulfide content coincidental with an increase in water production. Pioneer
developed a hydrogen sulfide contingency plan, which was required and approved by the MMS, and has installed the necessary alarm and safety systems. The well returned to production on
November 22, 2007 and is currently producing at 1-2 MMCFPD.

On
January 26, 2007, the Trustee reached a conditional settlement with Pioneer and Woodside of the claims asserted by the Plaintiffs against Pioneer and Woodside. The conditional
settlement was set forth in the Mutual Release and Settlement Agreement dated as of January 26, 2007 (the "Pioneer/Woodside Settlement Agreement"). The Trustee filed a motion for approval of
the Pioneer/Woodside Settlement Agreement with the Court on January 30, 2007. The Trustee believed that the Pioneer/Woodside Settlement Agreement was in the best interest of the unitholders,
but the Plaintiffs opposed it. On

11

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June 19,
2007, the Court issued an Order denying the Trustee's motion to approve the Pioneer/Woodside Settlement Agreement. The Court also issued an Order setting the trial date to
December 3, 2007.

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

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

As
of the date of this Form 10-K, there is no trial date set for the Lawsuit, but it is expected that the trial will be scheduled for late 2008. The Court has not yet entered a
new Docket Control Order to govern the schedule of the Lawsuit as it proceeds to trial.

The
Trustee will make the full detail of the underlying data of the December 31, 2007 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 DeGolyer & MacNaughton ("D&M"), see "Description of
Royalty Properties" in this Form 10-K and Note 8 in the Notes to Financial Statements included elsewhere in this Form 10-K. The final distribution to
unitholders will be an amount net of funds required to satisfy all Trust liabilities.

TIMING OF LIQUIDATION

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

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

12

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Trust Assets and Liabilities

As a result of the triggering of the Termination Threshold effective January 1, 2005, the Trust is in the process of liquidation. However, due to the
pending Lawsuit that directly challenges whether the Termination Threshold has in fact been met, the Trustee cannot predict the timing of the sale of all or a portion of the Royalty making up the
Partnership assets as part of the Trust liquidation and termination. The below table presents the assets of the Trust at their estimated fair value:

December 31,
2007ASSETSCash and short term investments

$
2,969Interest receivable


Net overriding royalty interest in oil and gas properties


1,328,863Total assets


1,331,832LIABILITIESReserve for Trust expenses

$
2,969Trust expenses payable


190,955Interest Payable


31,187Note payableJPMorgan


1,673,617Total liabilities


1,898,728Net assets in process of liquidation

$
(566,896
)


The
net overriding royalty interest in oil and gas properties at December 31, 2007 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, 2007. 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
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 "Description of Royalty Property" in this Form 10-K and
Note 8 in the Notes to Financial

13

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Statements
included elsewhere in this Form 10-K. The sale of the assets of the Trust estate may include the related rights to abandonment accruals made by PNR. As explained in
"Regulation and PricesPlatform Abandonment and Removal" on page 19 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, 2007.

DESCRIPTION OF ROYALTY PROPERTIES

Producing Acreage and Wells as of December 31, 2007

Producing Wells(1)Producing Acres

Gross

NetPropertyGross

Net(2)

Oil

Gas

Oil

GasOffshore Louisiana(3)West Delta 61

5,000

625



4



.5Offshore Texas(4)Brazos A-39

5,760

954



1



.05Total

10,760

1,579



5



.55




Reserves

A study of the proved oil and gas reserves attributable to the Partnership as of December 31, 2007, has been made by D&M in a letter (the "Reserve Report")
attached as Exhibit 99(a) and incorporated herein by reference. The Reserve Report reflects estimated reserve quantities and future net revenue based upon estimates of the future timing of
actual production without regard to when received in cash by the Trust, which differs from the manner in which the Trust recognizes and accounts for its Royalty income. The following tables are based
on the information contained in the Reserve Report and
summarize (1) estimates of the Trust's gross and net proved reserves as of December 31, 2007, and (2) the estimated future revenue and costs attributable to the Trust's royalty
interest in the proved reserves, as of December 31, 2007, of the properties evaluated.

Oil and
Condensate
(bbl)

Sales Gas
(Mcf)Gross Reserves Proved

135,283

3,955,609Net Reserves Proved

10,391

276,858


|
|

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Proved
($)Future Gross Revenue

2,900,239Operating Expenses

Capital Costs

(1,476,367
)Future Net Revenue*

1,423,872Present Worth at 10 Percent*

1,192,446




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

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

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, 2007. These prices (having weighted average year end prices of $92.52 to $95.95 per barrel of oil and condensate and $6.94 to $7.33 per Mcf of natural gas as of
December 31, 2007) 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 2007 was $6.79 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 $53.84 per barrel. See Management's Discussion and Analysis of
Financial Condition and Results of Operations "Financial and Operational OverviewProduction and Price Review" of this Form 10-K.

The
following is a summary of the estimated remaining life for each of the Royalty Properties provided to the Trustee by D&M as of December 31, 2007. There are numerous
uncertainties present in estimating the remaining productive lives for the Royalty Properties. The following summary

15

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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

7 yearsBrazos A-39

4 years




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
$2,500,000 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 2007 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 2007 were generally lower than spot market prices in 2006.

Market for Natural Gas

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

16

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distributions
are made to unitholders, the seasonality that generally affects production volumes and prices is generally reflected in distributions to unitholders in later periods.

Competition

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

Marketing of Liquids

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

REGULATION AND PRICES

General

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

17

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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.See49 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

18

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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,
2007. See Item 7 of this Form 10-K and Note 4 in the Notes to Financial Statements for amounts withheld as of December 31, 2007 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.

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

On
September 28, 2007, the Trust entered into a Demand Promissory Note agreement with JPMorgan in order to cover portions of its operating expenses. The lender approved an
uncommitted line

19

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

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

Interest
is payable at a base rate offered by JPMorgan as announced publicly at its principal office as its prime commercial lending rate, plus 2%. The rate effective as of
December 31, 2007 was a Prime Rate of 7.25%, plus 2% for a combined rate of 9.25%.

As
of December 31, 2007, there was outstanding $1,673,617 of principal advanced for payment of Trust expenses together with $31,187 of accrued and unpaid interest expense. At
December 31, 2007, the Trust had $1,326,383 available under this facility. Should the Trust fully utilize the funds available under the Demand Promissory Note, the Trustee will attempt to
borrow additional money. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at all.

On
January 22, 2008, the court in which the Lawsuit was pending issued an Order denying the Joint Motion for approval of the Settlement Agreement. According to the terms of the
Amended Promissory Note, the note matured on this date as a result of the denial. According to the terms of the agreement, all portions of the outstanding principal under this note together with
accrued and unpaid interest became due, in full, on this date. As defined by the note, if the Trust fails to pay any amount of principal or interest when due, the Trust is considered in default of the
loan. Subsequent to December 31, 2007, the
Trust failed to pay the principal and all accrued interest on the accelerated due date of January 22, 2008. As a result of the occurrence of the maturity date, JPMorgan may demand payment at
any time. Additionally, JPMorgan has no further obligation to advance additional monies under the Demand Promissory Note.

In
addition, the Trust Indenture prohibits the Trustee from making any distributions until these loans are repaid in full. Due to the uncertain timing of potential sales of the Royalty
Properties in connection with the liquidation of the Trust and the outcome of pending litigation, and based on the estimated future net revenue and present worth of the Trust's interests in proved
reserves made by the independent reserve engineer as of December 31, 2007, it is possible that amounts received in connection with any such sales of Royalty Properties, net of other amounts
payable in accordance with the Partnership Agreement and other liabilities of the Trust, may not exceed amounts then outstanding under the Amended and Restated Note.

20

---



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:



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 4 to the Notes to Financial Statements, at December 31, 2007 PNR estimated the Trust's portion of incurred and future abandonment
costs to be approximately

21

---



$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, 2007, approximately $1.1 million 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

22

---



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 terminated.

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

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

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

23

---





Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of distributions to unitholders attributable to depletion may be considered a
return of capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the Trust unitholders, which could
reduce the market value of the Trust units over time. Eventually, properties underlying the Trust's Royalty will cease to produce in commercial quantities and the Trust will, therefore, cease to
receive any distributions of net proceeds therefrom.

Unitholders have limited voting rights.

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

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

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

The limited liability of the Trust unitholders is uncertain.

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

Item 1B.    Unresolved Staff Comments.

There were no unresolved Securities and Exchange Commission comments as of December 31, 2007.

Item 2.    Properties.

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

Item 3.    Legal Proceedings.

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

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

There were no matters submitted to a vote of unitholders during the fourth quarter of 2007.

24

---



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 2007, the Trust had no gross Royalty income. No Royalty income will be distributed to the unitholders until the Trustee recoups Trust
expenses being paid from the reserve that the Trustee has established for anticipated future expenses and any loans secured by the Trustee to pay Trust expenses are repaid in full. The high and low
sales prices and distributions per unit for each quarter in the two years ended December 31, 2007 were as follows:

2007

2006High

Low

Distribution
Paid

High

Low

Distribution
PaidFirst Quarter

$
0.15

$
0.06

$


$
0.23

$
0.10

$
Second Quarter

$
0.12

$
0.07

$


$
0.18

$
0.09

$
Third Quarter

$
0.10

$
0.08

$


$
0.16

$
0.09

$
Fourth Quarter

$
0.40

$
0.05

$


$
0.10

$
0.05

$



At
March 20, 2008, the 71,980,216 units outstanding were held by 11,346 unitholders of record.

Item 6.    Selected Financial Data.

2007

2006

2005

2004

2003Royalty income

$


$
145,642

$
2,284,914

$


$
Distributable income

$


$


$


$


$
Distributable income per unit

$


$


$


$


$
Accumulated deficit at year end(1)

$
(1,477,002
)
$
(1,417,808
)
$


$
(59,035
)
$
(696,712
)Expenses Payable(2)


190,955











Trust Accrued Interest Expense


31,187











Note Payable  JPMorgan(3)

$
1,673,617

$


$


$


$
Total assets at year end

$
5,906

$
802,981

$
1,851,428

$
387,986

$
951,557




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.

25

---



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. Trust expenses payable and the note payable at
December 31, 2007 are reported as a reduction in Trust Corpus.

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

Status of the Trust

Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties informed PNR that the West Delta properties 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 production at West Delta resumed at all four wells in the fourth
quarter of 2007 at a combined production rate of 4.8 MMCFD.

The
Trust Indenture provides that the Trust will liquidate and terminate if the total amount of cash per year received by the Trust falls below certain levels for each of three
successive years.As a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the
Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture. The Trustee has previously taken steps to begin the process of liquidating
the Trust; however, due to the pending Lawsuit that directly challenges whether the Termination Threshold has in fact been met, the Trustee cannot predict the timing of the sale of all or a portion of
the Royalty making up the assets of the Partnership as part of the Trust liquidation and termination. See "BusinessTiming of Liquidation" 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 control over
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 assets of the Partnership. 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.

26

---





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

Properties producing as of December 31, 2007

Property

Number of
Producing
wells(1)

Estimated
Productive
Life(1)

Estimated
Future
Royalty
Income(2)West Delta No. 61

3

7 years

$
2,567,975Brazos A-39

1

4 years

$
332,264




Properties abandoned or scheduled for abandonment as of December 31, 2007

Property

StatusBrazos A-7

Abandoned in 2005 (Newfield platform abandoned in 2007)Brazos A-39

Plug and abandonment procedures completed in 2005 (excluding Midway prospect)*West Delta 62

Plug and abandonment procedures completed in 2003South Marsh Island 155

Plug and abandonment procedures completed in 2002South Marsh Island 156

Plug and abandonment procedures completed in 2002Vermillion 381

Plug and abandonment procedures completed in 1989South Pelto 12

Plug and abandonment procedures completed in 1986Matagorda Island 624

Plug and abandonment procedures completed in 2003High Island 567

Plug and abandonment procedures completed in 1992




Financial and Operational Review

As discussed in Item 1 of this Form 10-K, PNR has advised the Trust that during 2007, 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 lower in 2007 than spot market prices in 2006.

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.

27

---



Below
is a summary of Royalty income received on the Trust properties for each of the years ended December 31, 2007, 2006 and 2005:

2007

2006

2005Gross proceeds @ 90%

$
29,550

$
239,356

$
2,085,418Operating expenditures @ 90%


(88,649
)

(103,476
)

(104,265
)Change in abandonment estimate @ 90%





(1,400,139
)

Capital expenditures @ 90%(1)





(8,034
)

375,338Net proceeds (deficit)


(59,099
)

(1,272,293
)

2,356,491Increase (decrease) in deficit


59,099


1,417,950


(71,349
)Net proceeds after deficit recovery





145,657


2,285,142Royalty income (99.99%)

$


$
145,642

$
2,284,914




Below
is a summary of distributable income for the years ended December 31, 2007, 2006 and 2005:

Years Ended December 31,2007

2006

2005Royalty income

$


$
145,642

$
2,284,914Interest income


5,080


29,293


8,512General and administrative expenses


(5,080
)

(174,935
)

(2,293,426
)Distributable income

$


$


$
Distributable income per unit

$


$


$
Accumulated deficit (as of period end)

$
(1,477,002
)
$
(1,417,808
)
$



The
Trust had no distributable income in 2007, 2006 and 2005. Interest income and the reserve for Trust expenses were used to pay $802,155 of the Trust's general and administrative
expenses of $2,666,727 for the year ended December 31, 2007. The Trust had unpaid expenses of $190,955 as of December 31, 2007. On September 28, 2007 the Trust entered into a
Demand Promissory Note with JPMorgan which was amended on December 3, 2007, in which loans will be advanced by the lender from time to time not to exceed $3.0 million. This Demand
Promissory Note will be used to pay any unpaid administrative expenses related to the operation of the Trust. As of December 31, 2007, approximately $1,673,617 has been advanced to the Trust to
pay Trust expenses.

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

Years Ended December 31,2007

2006

2005General and administrative costs incurred during the year

$
2,666,727

$
1,223,271

$
824,691(Deductions from) additions to reserve for Trust Expenses


(797,075
)

(1,048,336
)

1,456,428Expenses paid through advances from JPMorgan Chase Bank via the promissory note


(1,673,617
)




Unpaid Trust Expenses


(190,955
)




General and administrative costs as reported

$
5,080

$
174,935

$
2,281,119


28

---



General
and administrative expenses of the Trust for 2007 increased 118% to $2,666,727 for 2007 as compared to $1,223,271 for 2006. The increase in general and administrative expenses in
2007 is primarily due to an increase in legal fees as a result of pending litigation as described in "Legal Proceedings." The Trust incurred additional expenditures in 2005 for the independent reserve
studies performed as of March 31, 2005 and December 31, 2005 and for the independent joint venture auditor to perform a review of certain historical expenditures and revenue receipts on
Trust properties.

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

Brazos A-7 and A-39

2007

2006

2005Gross proceeds @ 90%

$
29,550

$
152,215

$
156,378Operating expenditures @ 90%


(60,705
)

(87,211
)

(83,470
)Change in abandonment estimate @ 90%


(373
)

(1,269,806
)

Capital expenditures @ 90%








6,750Net proceeds (deficit)

$
(31,528
)
$
(1,204,802
)
$
79,658


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, 2007,
these two blocks had one well capable of producing, the Brazos A-39 #5 well. The Brazos A-7 No. B-1 well, operated by Newfield, is no longer producing as of
December 31, 2006 and was abandoned in 2007. 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 well, was drilled on Brazos A-39, which PNR announced as a discovery. A production test was completed in 2005.
PNR, the operator on this property, 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 well was shut-in on April 18, 2007 due to an increase in hydrogen sulfide content coincidental
with an increase in water production. PNR implemented a hydrogen sulfide contingency plan which was approved by the MMS. The well returned to production in the fourth quarter of 2007 after the
installation of the required safety equipment. The current production rate is 1-2 MMCFD with 4,500 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

29

---



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

2007

2006

2005Gross proceeds @ 90%

$


$
87,141

$
1,929,040Operating expenditures @ 90%


(27,944
)

(16,265
)

(20,795
)Change in abandonment expenditures @90%


373


(130,333
)

Capital expenditures @ 90%





(8,034
)

Net proceeds (deficit)

$
(27,571
)
$
(67,491
)
$
1,908,245


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 production at West Delta resumed at all four wells in the fourth quarter
2007 at a combined production rate of 4.8 MMCFD. The proceeds for the year ended December 31, 2006 consist of revenue adjustments related to prior periods received by the Trust during 2006.

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

Capital Expenditures

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

30

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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, 2004:

Balance, January 1, 2004

$
2,800,643Abandonment cost incurred (Mat. Is. 624 & WD 62)


(124,492
)Balance, December 31, 2004

$
2,676,151Abandonment cost incurred (Brazos A-7A, A-7#4,A-39A1A,A-2 and A-3A)


(2,328,085
)Balance, December 31, 2005

$
348,066Abandonment cost incurred (Brazos A-7#4,A-39A1A,A-2 and A-3A Matagorda Island 624, South Marsh Island 155)


(348,066
)Balance, December 31, 2006

$
Balance, December 31, 2007

$



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, 2007, PNR has spent approximately $1.1 million of the $1.4 million estimate, while approximately $329,000 of PNR's original estimate for total abandonment
remains to be spent. As the reserve for future abandonment cost was fully utilized during 2006, 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 the Partnership 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. Based on the current general and administrative expenditures being
incurred in connection with the litigation and the absence of Royalty income, the Trustee was required to borrow money in accordance with the Trust Indenture to fund Trust expenses. On
September 28, 2007 the Trust entered into a Demand Promissory Note agreement with JPMorgan in order to cover portions of its operating expenses. The lender approved an uncommitted line of
credit to the Trust in a principal amount not to exceed $3 million. As part of that agreement, JPMorgan pays the expenses on behalf of the Trust. JPMorgan may decline to fund any request of the
Trust for borrowings at anytime, for any reason, including the event that JPMorgan has reason to believe that the Trust will not be able to satisfy its obligation to repay the Demand Loans. Interest
on the note is calculated at a rate per annum equal to Prime Rate plus two percent (2%), paid annually. The Demand Promissory Note is secured by a pledge of the Trust Estate, as that term is defined
in the Trust Indenture, including without limitation the 99.99% general partnership interest in the Mesa Offshore Royalty Partnership owned by the Trust, pursuant to a Pledge Agreement dated
September 29, 2007, as amended by the First Amendment to Pledge Agreement dated as of December 3, 2007, executed by the Trust for the benefit of the Lender. The Trust may borrow amounts
under this Note until such time as JPMorgan makes demand for payment in full or

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December 31,
2008, whichever is earlier. On December 3, 2007, JPMorgan, individually and as lender, entered into an Amended and Restated Promissory Note, with the Trust as borrower, to
amend the Demand Promissory Note to provide for, among other provisions, an extension of the stated maturity date of the Loans made pursuant to the Demand Promissory Note and the Amended and Restated
Note until the earlier of (1) December 31, 2009, (2) 31 days after the Trust's receipt of any settlement proceeds, recovery or judgment in connection with the Lawsuit,
(3) final liquidation of the Trust's assets, or (4) the Settlement Agreement is not approved by the Court. Additionally, the amendment provided that the Trust may continue to obtain
loans under the note until the maturity date, as long as, the amount borrowed does not exceed $3 million and the loan is not in default. The amendment also provided that interest expense shall
be due and payable on the maturity date. As of December 31, 2007, there was outstanding $1,673,617 of principal advanced for payment of Trust expenses together with $31,187 of accrued and
unpaid interest expense. At December 31, 2007, the Trust had $1,326,383 available under this facility. Should the Trust fully utilize the funds available under the Demand Promissory Note, the
Trustee will attempt to borrow additional money. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at all. The Trust
Indenture prohibits the Trustee from making any distributions to unitholders until these loans are repaid in full.

On
January 22, 2008, the court in which the Lawsuit was pending issued an order denying the Joint Motion for approval of the Settlement Agreement. According to the terms of the
Amended Promissory Note, the note matured on this date as a result of the denial. According to the terms of the agreement, all portions of the outstanding principal under this note together with
accrued and unpaid interest became due, in full, on this date. As defined by the note, if the Trust fails to pay any amount of principal or interest when due, the Trust is considered in default of the
loan. Subsequent to December 31, 2007, the Trust failed to pay the principal and all accrued interest on the accelerated due
date of January 22, 2008. As a result of the occurrence of the maturity date, JPMorgan may demand payment at any time. Additionally, JPMorgan has no further obligation to advance additional
monies under the Demand Promissory Note.

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

Production and Price Review

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

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.

Off-Balance Sheet Arrangements

None.

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

Not applicable.

32

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Item 8.    Financial Statements and Supplementary Data.

MESA OFFSHORE TRUST  STATEMENTS OF DISTRIBUTABLE INCOME

|                                    |  | Years Ended December 31, |       
|----------------------------------- |  | ------------------------ | ------
|
|Royalty income                      |  | $                        |      
|Interest income                     |  |                          | 5,080 
|General and administrative expenses |  |                          | (5,080
|                                    |  |                          |       
|Distributable income                |  | $                        |      
|                                    |  |                          |       
|Distributable income per unit       |  | $                        |      
|                                    |  |                          |       

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

|                                                                                     |                                | December 31, |            
|------------------------------------------------------------------------------------ | ------------------------------ | ------------ | -----------
|
|ASSETS                                                                               |                                |              |            
|Cash and short-term investments                                                      |                                | $            | 2,969      
|Interest receivable                                                                  |                                |              |           
|Net overriding royalty interest in oil and gas properties                            |                                |              | 380,905,000
|                                                                                     | Less: accumulated amortization |              |            
|                                                                                     |                                |              |            
|Total assets                                                                         |                                | $            | 5,906      
|                                                                                     |                                |              |            
|LIABILITIES AND TRUST CORPUS                                                         |                                |              |            
|Reserve for trust expense                                                            |                                | $            | 2,969      
|Trust expense payable                                                                |                                |              | 190,955    
|Interest payable                                                                     |                                |              | 31,187     
|Note payableJPMorgan                                                                |                                |              | 1,673,617  
|Trust Corpus (71,980,216 units of beneficial of interest authorized and outstanding) |                                |              | (1,892,822 
|                                                                                     |                                |              |            
|Total liabilities and trust corpus                                                   |                                | $            | 5,906      
|                                                                                     |                                |              |            

STATEMENTS OF CHANGES IN TRUST CORPUS

|                                                |  | Years Ended December 31, |           
|----------------------------------------------- |  | ------------------------ | ----------
|
|Trust corpus, beginning of year                 |  | $                        | 2,937     
|Trust expenses payable                          |  |                          | (190,955  
|Interest payable                                |  |                          | (31,187   
|Note payableJPMorgan                           |  |                          | (1,673,617
|Amortization of net overriding royalty interest |  |                          |          
|                                                |  |                          |           
|Trust corpus, end of year                       |  | $                        | (1,892,822
|                                                |  |                          |           

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

33

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MESA OFFSHORE TRUST        NOTES TO FINANCIAL STATEMENTS

(1)   Trust Organization and Provisions



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

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

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

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

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

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

(e)   the
Trust will terminate upon the first to occur of the following events: (i) the total amount of cash received per year by the Trust for each of three successive
years commencing after December 31, 1987 is less than ten times one-third of the total amount payable to the Trustee as compensation for such three-year period (the
"Termination Threshold") or (ii) a vote by holders of a majority of the outstanding units in favor of termination. Amounts earned by the Trustee as compensation were approximately $177,000,
$360,000 and $204,000 for the years 2007, 2006 and 2005, respectively. As described further in "Legal Proceedings and Status of the Trust" below, the Termination Threshold was met in the three
consecutive years ending December 31, 2004. However, due to pending litigation involving the Trust that directly challenges whether the Termination Threshold has in fact been met, the Trustee
cannot predict the timing of the sale of all or a portion of the Partnership assets as part of the Trust liquidation and termination. As part of the liquidation and eventual termination of the Trust,
the Trustee will sell for cash all the assets held by the Partnership and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied.



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

34

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("PNR")
(successor to Mesa), a wholly owned subsidiary of PNRC (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, PNR owns and operates its assets through
PNRC and is also the managing general partner of the Partnership.

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



The
Trust Indenture provides that the Trust will liquidate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of insufficient production on Royalty
Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004
fell below the Termination Threshold prescribed by the Trust Indenture. The Trustee has previously taken steps to begin the process of liquidating the Trust; however, the legal
proceedings described herein directly challenge whether the Termination Threshold has in fact been met and thus have affected the liquidation process. See "BusinessTiming of Liquidation"
beginning on page 12 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 control over the occurrence of the Termination Threshold or its consequences.

The
Trust Indenture provides the Trustee a two-year period during which it must sell all of the assets of the Partnership. In 2005, the Trustee began procedures to liquidate
the Trust's assets; however, due to the pending litigation, the Trustee can not predict the timing of the sale of the assets. The Trust Indenture provides that such properties must be sold for cash
and not for any other consideration. The Trustee expects that 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.

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 PNRC; PNR;
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 drilled thereon, (3) fraudulent accounting practices by Pioneer,
(4) breach of fiduciary duty by Pioneer, (5) aiding and abetting breach of fiduciary duty by Woodside, (6) misapplication of Trust property by Pioneer, (7) conspiracy to
misapply fiduciary property by Woodside and Pioneer, (8) common law fraud by Pioneer, (9) gross negligence by Pioneer, and (10) breach of the conveyance agreement by Pioneer. As
described below, 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

35

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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.

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 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.

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 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 damage 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

36

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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. MHLP and the Intervenors are referred to hereinafter as the "Plaintiffs."

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 the Plaintiffs. The well resumed production in February 2007. The well was shut in again on April 18, 2007 due to an increase in hydrogen sulfide content
coincidental with an increase in water production. Pioneer developed a hydrogen sulfide contingency plan, which was required and approved by the MMS, and will install the
necessary alarm and safety systems. The well returned to production on November 22, 2007 and is currently producing at 1-2 MMCFPD.

On
January 26, 2007, the Trustee reached a conditional settlement with Pioneer and Woodside of the claims asserted by the Plaintiffs against Pioneer and Woodside. The conditional
settlement was set forth in the Mutual Release and Settlement Agreement dated as of January 26, 2007 (the "Pioneer/Woodside Settlement Agreement"). The Trustee filed a motion for approval of
the Pioneer/Woodside Settlement Agreement with the Court on January 30, 2007. The Trustee believed that the Pioneer/Woodside Settlement Agreement was in the best interest of the unitholders,
but the Plaintiffs opposed it. On June 19, 2007, the Court issued an Order denying the Trustee's motion to approve the Pioneer/Woodside Settlement Agreement. The Court also issued an Order
setting the trial date to December 3, 2007.

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

37

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

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

As
of the date of this Form 10-K, there is no trial date set for the Lawsuit, but it is expected that the trial will be scheduled for late 2008. The Court has not yet entered a
new Docket Control Order to govern the schedule of the Lawsuit as it proceeds to trial.

The
Trustee will make the full detail of the underlying data of the December 31, 2007 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 Note 8 in the Notes to Financial Statements. The final
distribution to unitholders will be an amount net of funds required to satisfy all Trust liabilities.

(2)   Going Concern

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

During
the two years ended December 31, 2007, the Trust incurred general and administrative expenses which exceeded Royalty and interest income and its available cash reserves,
due to the absence of royalty income and expenses incurred in connection with the ongoing litigation. As such, the Trustee was required to borrow money in accordance with the Trust Indenture to fund
Trust expenses. The Trustee entered into a Demand Promissory Note with JPMorgan on September 28, 2007, which was amended on December 3, 2007, for demand loans that may be advanced from
time to time in the principal amount of up to $3.0 million. As of December 31, 2007, the Trust had $1,673,617 in principal

38

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outstanding
and $31,187 in accrued and unpaid interest expense, leaving $1,326,383 available under this facility. Additionally, as of December 31, 2007, the Trust had $2,969 in available cash
and $190,955 in unpaid trust expenses. Should the Trust fully utilize the funds available under the Demand Promissory Note, the Trustee will attempt to borrow additional money. However, no assurance
can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable, or at all.

On
January 22, 2008, the court in which the lawsuit was pending issued an Order denying the Joint Motion for approval of the Settlement Agreement. According to the terms of the
Amended Promissory Note, the note matured on this date as a result of the denial, and all portions of the outstanding principal under this note together with accrued and unpaid interest became due, in
full, on this date. As defined by the note, if the Trust fails to pay any amount of principal or interest when due, the Trust is considered in default of the loan. Subsequent to December 31,
2007, the Trust failed to pay the principal and all accrued interest on the accelerated due date of January 22, 2008. As a result of the occurrence of the maturity date, JPMorgan may demand
payment at any time and JPMorgan has no further obligation to advance additional monies under the Demand Promissory Note; however, JPMorgan has not issued a notice of acceleration or demand letter and
has funded the Trust expenses through the month of March 2008.

If
JPMorgan issues a demand letter demanding that the outstanding principal and accrued and unpaid interest expense be paid immediately, the Trust does not have the cash resources
available to repay the debt. If the Trustee is unable to renegotiate the terms of the debt or secure additional financing, this could raise substantial doubt regarding the Trust's ability to continue
as a going concern. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

(3)   Net Overriding Royalty Interest

The instruments conveying the Royalty to the Partnership provide that PNR will calculate and pay to the Partnership each month an amount equal to 90% of aggregate
net proceeds for the preceding month. Generally, net proceeds means the excess of the amounts received by PNR from sales of its share of oil and gas from the Royalty Properties (gross proceeds) over
the operating and capital costs incurred. Costs exceeding gross proceeds for any month are recovered by PNR, with interest thereon at the prime rate of the Bank of America plus one-half
percent, out of future gross proceeds prior to making further royalty payments to the Partnership.

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

(4)   Basis of Accounting

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

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

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

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

This
basis for reporting distributable income is considered to be the most meaningful because distributions to the unitholders for a month are based on net cash receipts for such month.
However, it

39

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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. As of December 31, 2007, there is a deficit balance due PNR of approximately $1.5 million, which will be deducted from any future gross proceeds on
the Royalty properties, which will reduce future Royalty income. Currently, PNR estimates that the abandonment accrual for amounts expended but not recouped and for projected future abandonment
expenses for properties in which the Trust has an interest is $1.4 million, net to the Trust, which is included in the deficit balance above. These costs 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 until the Trustee recoups Trust expenses being paid from the reserve that the Trustee has established for anticipated future general
and administrative expenses and any loans secured by the Trustee to pay Trust expenses are repaid in full. As of December 31, 2007 and 2006, $3,892,787 and $1,199,956, respectively, will be
recouped by the Trustee from future Royalty income before Trust distributions will resume. During the twelve months ended
December 31, 2007, no royalty income or proceeds from the sale of the properties was received by the Trust; accordingly no Trust distribution was made to the unitholders.

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

Years Ended December 31,2007

2006

2005General and administrative costs incurred during the year

$
2,666,727

$
1,223,271

$
824,691(Deductions from) additions to reserve for trust expenses


(797,075
)

(1,048,336
)

1,456,428Expenses paid by JP Morgan during current period


(1,673,617
)Unpaid trust expenses


(190,955
)




General and administrative costs as reported

$
5,080

$
174,935

$
2,281,119


(5)   JPMorgan Demand Promissory Note

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

40

---



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

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

Interest
is payable at a base rate offered by JPMorgan as announced publicly at its principal office as its prime commercial lending rate, plus 2%. The rate effective as of
December 31, 2007 was a Prime Rate of 7.25%, plus 2% for a combined rate of 9.25%.

As
of December 31, 2007, there was outstanding $1,673,617 of principal advanced for payment of Trust expenses together with $31,187 of accrued and unpaid interest expense. At
December 31, 2007, the Trust had $1,326,383 available under this facility. Should the Trust fully utilize the funds available under the Demand Promissory Note, the Trustee will attempt
to borrow additional money. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at all.

On
January 22, 2008, the court in which the lawsuit was pending issued an Order denying the Joint Motion for approval of the Settlement Agreement. According to the terms of the
Amended Promissory Note, the note matured on this date as a result of the denial. According to the terms of the agreement, all portions of the outstanding principal under this note together with
accrued and unpaid interest became due, in full, on this date. As defined by the note, if the Trust fails to pay any amount of
principal or interest when due, the Trust is considered in default of the loan. Subsequent to December 31, 2007, the Trust failed to pay the principal and all accrued interest on the
accelerated due date of January 22, 2008. As a result of the occurrence of the maturity date, JPMorgan may demand payment at any time. Additionally, JPMorgan has no further obligation to
advance additional monies under the Demand Promissory Note.

(6)   Distributions to Unitholders

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

(7)   Federal Income Taxes

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

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

41

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(8)   Supplemental Reserve Information (Unaudited)

Estimates of the proved oil and gas reserves attributable to the Royalty as of December 31, 2007, 2006 and 2005, are based on a report prepared by DeGolyer
and MacNaughton ("D&M"). 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 $2,500,000 annually. The general and administrative expenses of the Trust may increase for the remaining duration of the Trust, depending on the amount of royalty income, increases in
accounting, engineering, legal, and other professional fees and other factors.

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

42

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Estimated Quantities of Proved and Proved Developed Reserves (Unaudited)

|                           |                                             | Oil and
Condensate |         | Natural
Gas |         
|-------------------------- | ------------------------------------------- | ------------------ | ------- | ----------- | --------
|
|Proved Reserves:           |                                             |                    |         |             |         
|                           | 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 
|                           | Revisions of previous estimates             |                    | (203    | )           | (79,006 
|                           | Extensions, discoveries and other additions |                    |        |             |        
|                           | Production                                  |                    | (19     | )           | (4,198  
|                           |                                             |                    |         |             |         
|                           | December 31, 2007                           |                    | 10,391  |             | 276,858 
|Proved Developed Reserves: |                                             |                    |         |             |         
|                           | December 31, 2004.                          |                    | 5,960   |             | 174,510 
|                           | December 31, 2005.                          |                    | 10,766  |             | 460,055 
|                           | December 31, 2006.                          |                    | 10,613  |             | 360,062 
|                           | December 31, 2007                           |                    | 10,391  |             | 276,858 

---

(See
Notes on following page.)

43

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

|                                                                               |                                                         | December 31, |      
|------------------------------------------------------------------------------ | ------------------------------------------------------- | ------------ | -----
|
|
|Ninety percent of future gross proceeds                                        |                                                         | $            | 2,900
|Less ninety percent of                                                        |                                                         |              |      
|                                                                               | Future operating costs                                  |              |      
|                                                                               | Future capital costs, net of amounts previously accrued |              |      
|                                                                               | Deficit due PNR                                         |              |      
|                                                                               |                                                         |              |      
|Future Royalty income                                                          |                                                         |              | 1,424
|Discount at 10% per annum                                                      |                                                         |              | (232 
|                                                                               |                                                         |              |      
|Standardized measure of future Royalty income from proved oil and gas reserves |                                                         | $            | 1,192
|                                                                               |                                                         |              |      

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, |      
|----------------------------------------- | --------------------------------------------- | ------------------------ | -----
|
|
|Standardized measure at beginning of year |                                               | $                        | 768  
|                                          | Revisions of previous estimates               |                          |      
|                                          | Net changes in prices and production costs    |                          |      
|                                          | Extensions, discoveries and other additions   |                          |      
|                                          | Changes in estimated future development costs |                          |      
|                                          | Royalty income                                |                          |      
|                                          | Accretion of discount                         |                          |      
|                                          |                                               |                          |      
|                                          | Net changes in standardized measure           |                          |      
|                                          |                                               |                          |      
|Standardized measure at end of year       |                                               | $                        | 1,192
|                                          |                                               |                          |      

---

(9)   Selected Quarterly Financial Data (Unaudited)

|                              |  | Summarized Quarterly Results
|----------------------------- |  | ----------------------------
|
|
|2007:                         |  |                             
|Royalty income                |  | $                           
|Distributable income          |  | $                           
|Distributable income per unit |  | $                           
|2006:                         |  |                             
|Royalty income                |  | $                           
|Distributable income          |  | $                           
|Distributable income per unit |  | $                           

44

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We
have audited the accompanying statements of assets, liabilities and trust corpus of Mesa Offshore Trust as of December 31, 2007 and 2006, and the related statements of
distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2007. These financial statements are the responsibility of the
Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.

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

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

In
our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of Mesa Offshore Trust as of
December 31, 2007 and 2006, and the distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2007, in conformity
with the basis of accounting described in Note 4 to the financial statements.

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

| |  | KPMG LLP
| |  | --------

Houston,
Texas
April 9, 2008

45

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

None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures.The Trustee maintains disclosure controls and procedures designed to ensure
that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the
time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust
is accumulated and communicated by 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 and reserve information, as well as (iii) information relating to projected production;
(B) information provided by the managing general partner of the Partnership that is collected by the managing general partner from the working interest owners; and (C) conclusions
regarding reserves by reserve engineers or other experts in good faith. See Item 1A. Risk Factors "The unitholders and the Trustee have no control over the operation or development
of the Royalty Properties and have little influence over operation or development" and "The Trustee relies upon the working interest owners and managing general partner for information
regarding the Royalty Properties" in this Form 10-K for a description of certain risks relating to these arrangements and reliance.

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

Trustee's Report on Internal Control over Financial Reporting.The Trustee is responsible for establishing and maintaining
adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. The Trustee
conducted an evaluation of the effectiveness of the Trust's internal control over financial reporting ("internal control over financial reporting") based on the criteria established in
"Internal Control-Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee's
evaluation under the framework in "Internal Control-Integrated Framework," the Trustee concluded that the Trust's internal control over financial
reporting was effective as of December 31, 2007.

The
Trustee does not expect that the Trustee's disclosure controls and procedures relating to the Trust or the Trustee's internal control over financial reporting relating to the Trust
will prevent all

46

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errors
and all fraud. A registrant's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A registrant's internal control over financial reporting includes those policies
and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified basis of accounting discussed above,
and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrant's assets that could have a material effect on the financial statements.

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

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

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

47

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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 2007.

Item 11.    Executive Compensation.

Not applicable.

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

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

---

48

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

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

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

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

On
January 22, 2008, the court in which the Lawsuit was pending issued an Order denying the Joint Motion for approval of the Settlement Agreement. According to the terms of the
Amended Promissory Note, the note matured on this date as a result of the denial. According to the terms of the agreement, all portions of the outstanding principal under this note together with
accrued and unpaid interest became due, in full, on this date. As defined by the note, if the Trust fails to pay any amount of principal or interest when due, the Trust is considered in default of the
loan. Subsequent to December 31, 2007, the Trust failed to pay the principal and all accrued interest on the accelerated due date of January 22, 2008. As a result of the occurrence of
the maturity date, JPMorgan may demand payment at any time. Additionally, JPMorgan has no further obligation to advance additional monies under the Demand Promissory Note.

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.

49

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The
following table presents fees for professional audit services rendered by KPMG LLP for the audit of the Mesa Offshore Trust financial statements for 2007 and 2006 and fees
billed for other services rendered by KPMG LLP.

|                   |            | 2007    |         | 2006
|------------------ | ---------- | ------- | ------- | ----
|Audit fees(1)      |            | 195,000 |         | $   
|Audit-related fees |            |        |         |     
|Tax fees(2)        |            | 25,000  |         |     
|All other fees     |            |        |         |     
|                   |            |         |         |     
|                   | Total fees |         | 220,000 |     
|                   |            |         |         |     

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50

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PART IV

Item 15.    Exhibits, Financial Statement Schedules.



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                               |  | 33                    
|Statements of Assets, Liabilities and Trust Corpus               |  | 33                    
|Statements of Changes in Trust Corpus                            |  | 33                    
|Notes to Financial Statements                                    |  | 34                    
|Report of Independent Registered Public Accounting FirmKPMG LLP |  | 45                    



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



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

|   |     |                                                                                                                                                                                                                                                                                     |  | SEC File or
Registration
Number |  | Exhibit
Number
|-- | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------- |  | --------------
|4  | (a) | *Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982                                                                                                                                         |  | 2-79673                         |  | 10(gg)        
|4  | (b) | *Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty Partnership, dated December 15, 1982                                                                                                                                                            |  | 2-79673                         |  | 10(hh)        
|4  | (c) | *Partnership Agreement between Mesa Offshore Management Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982                                                                                                                                       |  | 2-79673                         |  | 10(ii)        
|4  | (d) | *Amendment to Partnership Agreement between Mesa Offshore Management Co., Texas Commerce Bank National Association, as Trustee, and Mesa Operating Limited Partnership, dated December 27, 1985 (Exhibit 4(d)
to Form 10-K for year ended December 31, 1992 of Mesa Offshore Trust) |  | 1-8432                          |  | 4(d)          
|4  | (e) | *Amendment to Partnership Agreement between Texas Commerce Bank National Association, as Trustee, and Mesa Operating dated as of January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December 31,
1993 of Mesa Offshore Trust)                                                |  | 1-8432                          |  | 4(e)          
|10 | (a) | *Mutual Release and Settlement Agreement dated January 26, 2007 (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 31, 2007)                                                                                                                                   |  | 1-8432                          |  | 10.1          
|10 | (b) | *Demand Promissory Note, dated as of September 28, 2007 (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 3, 2007)                                                                                                                                            |  | 1-8432                          |  | 10.1          
|10 | (c) | *Pledge Agreement, dated as of September 28, 2007 (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on October 3, 2007)                                                                                                                                                  |  | 1-8432                          |  | 10.2          

51

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|10 | (d) | *Settlement Agreement and Release, effective December 3, 2007 by and among JPMorgan Chase Bank, N.A., JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust, and MOSH Holding, L.P.,
Intervenor-Plaintiff Dagger-Spine Hedgehog Corporation, and Intervenor-Plaintiffs Keith A. Wiegand, Ronnie McGlothlin, Gordon W. Bader, Roger L. Bean, Roger R. Bean, Jennifer J. Bean, Tracey M. Stump, Scott W. Bean,
James Blau, Larry W. Bradley, Richard Brown, Scott Curran, Ron Davis, Mark Dittus, John C. Easton, Jamie Arnold, John Easton Schwab Brokerage, John Easton Schwab Roth, John Easton Schwab IRA, John Easton Scottrade Brokerage, John Easton
Trust, Jamie Arnold Schwab IRA, Vicki Easton Schwab IRA, James Figielski, James Figielski Pension Plan, Ami Schecter, Ami Schecter Roth IRA, Kathleen Friend, Patricia L. Hendrix, Ben Hoos, Matt Hoos, Philip Hoos, John W. Hovanec,
Nicole M. Kimball, Matthew J. King, Darrell M. Leis, J.D. Maddox, Roy G. Maddox, John McCall, Katrina McGlothlin, Mary R. McNamara, Michael E. McNamara, Monika Meier, Mallory Mikkelsen, Dean P. Miles, Elizabeth A.
Miles-Cunningham, Lori Miles, Robert M. Miles, Sharon A. Miles, William Kevin Miles, Gara Sue Pelcher, Jeffrey T. Pelcher, The Pelcher Company Keogh Plan, Jeffrey Thomas Pelcher Custodial for Nathan Allen Pelcher Roth IRA, Gara Pelcher Ten
Com, Jeffrey T. Pelcher Custodial for Derrick T. Pelcher, Jeffrey T. Pelcher Custodial for Nathan A. Pelcher, Adriene Rohleder, John Selep, John M. Speight, Gordon A. Stamper, Jessica Stamper, Armin Sternberg, Robert Todd,
T.D. Tommey, Lyle Wagman, Barbara Wiedemann, Knut Wiedemann, Nichole Wiedemann, Jerry L. Wolf, and Galen R. Young (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on December 13, 2007) |  | 1-8432 |  | 10.1
|-- | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------ |  | ----
|10 | (e) | *Letter Agreement dated December 7, 2007 Amending and Modifying Settlement Agreement and Release (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on December 13, 2007)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |  | 1-8432 |  | 10.2
|10 | (f) | *Amended and Restated Promissory Note, dated December 3, 2007, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.3 to Form 8-K filed on
December 13, 2007)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |  | 1-8432 |  | 10.3
|10 | (g) | *First Amendment to Pledge Agreement, dated as of December 3, 2007, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.4 to Form 8-K filed on
December 13, 2007)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |  | 1-8432 |  | 10.4
|31 |     | Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |        |  |     
|32 |     | Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |        |  |     
|99 | (a) | DeGolyer and MacNaughton Appraisal Report as of December 31, 2007 on Proved Reserves of Certain Interests owned by Mesa Offshore Trust                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |  |        |  |     

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52

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SIGNATURES

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

|              |  | MESA OFFSHORE TRUST
|------------- |  | -------------------
|              |  | By                 
|April 9, 2008 |  | By:                

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.

53

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EXHIBIT INDEX

|EXHIBIT
NUMBER |     |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |  | SEC File or
Registration
Number |  | Exhibit
Number
|-------------- | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------- |  | --------------
|4              | (a) | *Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  | 2-79673                         |  | 10(gg)        
|4              | (b) | *Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty Partnership, dated December 15, 1982                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |  | 2-79673                         |  | 10(hh)        
|4              | (c) | *Partnership Agreement between Mesa Offshore Management Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |  | 2-79673                         |  | 10(ii)        
|4              | (d) | *Amendment to Partnership Agreement between Mesa Offshore Management Co., Texas Commerce Bank National Association, as Trustee, and Mesa Operating Limited Partnership, dated December 27, 1985 (Exhibit 4(d)
to Form 10-K for year ended December 31, 1992 of Mesa Offshore Trust)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |  | 1-8432                          |  | 4(d)          
|4              | (e) | *Amendment to Partnership Agreement between Texas Commerce Bank National Association, as Trustee, and Mesa Operating dated as of January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December 31,
1993 of Mesa Offshore Trust)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |  | 1-8432                          |  | 4(e)          
|10             | (a) | *Mutual Release and Settlement Agreement dated January 26, 2007 (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on January 31, 2007)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  | 1-8432                          |  | 10.1          
|10             | (b) | *Demand Promissory Note, dated as of September 28, 2007 (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 3, 2007)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |  | 1-8432                          |  | 10.1          
|10             | (c) | *Pledge Agreement, dated as of September 28, 2007 (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on October 3, 2007)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |  | 1-8432                          |  | 10.2          
|10             | (d) | *Settlement Agreement and Release, effective December 3, 2007 by and among JPMorgan Chase Bank, N.A., JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust, and MOSH Holding, L.P.,
Intervenor-Plaintiff Dagger-Spine Hedgehog Corporation, and Intervenor-Plaintiffs Keith A. Wiegand, Ronnie McGlothlin, Gordon W. Bader, Roger L. Bean, Roger R. Bean, Jennifer J. Bean, Tracey M. Stump, Scott W. Bean,
James Blau, Larry W. Bradley, Richard Brown, Scott Curran, Ron Davis, Mark Dittus, John C. Easton, Jamie Arnold, John Easton Schwab Brokerage, John Easton Schwab Roth, John Easton Schwab IRA, John Easton Scottrade Brokerage, John Easton
Trust, Jamie Arnold Schwab IRA, Vicki Easton Schwab IRA, James Figielski, James Figielski Pension Plan, Ami Schecter, Ami Schecter Roth IRA, Kathleen Friend, Patricia L. Hendrix, Ben Hoos, Matt Hoos, Philip Hoos, John W. Hovanec,
Nicole M. Kimball, Matthew J. King, Darrell M. Leis, J.D. Maddox, Roy G. Maddox, John McCall, Katrina McGlothlin, Mary R. McNamara, Michael E. McNamara, Monika Meier, Mallory Mikkelsen, Dean P. Miles,
Elizabeth A. Miles-Cunningham, Lori Miles, Robert M. Miles, Sharon A. Miles, William Kevin Miles, Gara Sue Pelcher, Jeffrey T. Pelcher, The Pelcher Company Keogh Plan, Jeffrey Thomas Pelcher Custodial for Nathan Allen Pelcher Roth
IRA, Gara Pelcher Ten Com, Jeffrey T. Pelcher Custodial for Derrick T. Pelcher, Jeffrey T. Pelcher Custodial for Nathan A. Pelcher, Adriene Rohleder, John Selep, John M. Speight, Gordon A. Stamper, Jessica Stamper, Armin
Sternberg, Robert Todd, T.D. Tommey, Lyle Wagman, Barbara Wiedemann, Knut Wiedemann, Nichole Wiedemann, Jerry L. Wolf, and Galen R. Young (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on December 13,
2007) |  | 1-8432                          |  | 10.1          

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|10 | (e) | *Letter Agreement dated December 7, 2007 Amending and Modifying Settlement Agreement and Release (Incorporated by reference to Exhibit 10.2 to Form 8-K filed on December 13, 2007)                                     |  | 1-8432 |  | 10.2
|-- | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------ |  | ----
|10 | (f) | *Amended and Restated Promissory Note, dated December 3, 2007, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.3 to Form 8-K filed on
December 13, 2007)      |  | 1-8432 |  | 10.3
|10 | (g) | *First Amendment to Pledge Agreement, dated as of December 3, 2007, by and between Mesa Offshore Trust and JPMorgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.4 to Form 8-K filed on
December 13, 2007) |  | 1-8432 |  | 10.4
|31 |     | Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                       |  |        |  |     
|32 |     | Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                       |  |        |  |     
|99 | (a) | DeGolyer and MacNaughton Appraisal Report as of December 31, 2007 on Proved Reserves of Certain Interests owned by Mesa Offshore Trust                                                                                  |  |        |  |     

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