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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549
                            ------------------------
                                   FORM 10-K

(MARK ONE)

<TABLE>
<C>        <S>
   /X/     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
           SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED
           DECEMBER 31, 2000
</TABLE>

<TABLE>
<C>        <S>
   / /     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
           SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD
           FROM TO
</TABLE>

                         COMMISSION FILE NUMBER 1-8432
                            ------------------------
                              MESA OFFSHORE TRUST

             (Exact Name of Registrant as Specified in Its Charter)

<TABLE>
<S>                                            <C>
               NEW YORK                                     76-6004065
    (State or Other Jurisdiction of                      (I.R.S. Employer
    Incorporation or Organization)                     Identification No.)
       THE CHASE MANHATTAN BANK,                              77002
     INSTITUTIONAL TRUST SERVICES                           (Zip Code)
            712 MAIN STREET
            HOUSTON, TEXAS
    (Address of Principal Executive
               Offices)
</TABLE>

       REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 1-800-852-1422

          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

<TABLE>
<CAPTION>
                                NAME OF EACH EXCHANGE ON
      TITLE OF EACH CLASS           WHICH REGISTERED
      -------------------           ----------------
  <S>                           <C>
  Units of Beneficial Interest     Pacific Exchange
</TABLE>

          SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
                                      NONE

    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 /X/  No / /

    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. /X/

    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 March 23, 2001, of $.1094 was approximately $7,874,636.

    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 23, 2001, 71,980,216 Units of Beneficial Interest in Mesa
Offshore Trust.

    Documents Incorporated By Reference: None.

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<PAGE>
                               TABLE OF CONTENTS

                                     PART I

<TABLE>
<CAPTION>
                                                                                        PAGE
                                                                                      --------
<S>                     <C>                                                           <C>
Item 1.                 Business....................................................         1
                        Description of the Trust....................................         1
                        Description of the Units....................................         2
                        Termination of the Trust....................................         5
                        Description of Royalty Properties...........................         6
                        Contracts...................................................        12
                        Regulation and Prices.......................................        13
Item 2.                 Properties..................................................        15
Item 3.                 Legal Proceedings...........................................        15
Item 4.                 Submission of Matters to a Vote of Security Holders.........        15

                                           PART II
Item 5.                 Market for the Registrant's Common Equity and Related
                        Unitholder Matters..........................................        16
Item 6.                 Selected Financial Data.....................................        16
Item 7.                 Management's Discussion and Analysis of Financial Condition
                        and Results of Operations...................................        16
                        Net Proceeds, Production and Average Prices (Unaudited).....        20
Item 8.                 Financial Statements and Supplementary Data.................        22
Item 9.                 Changes in and Disagreements with Accountants on Accounting
                        and Financial Disclosure....................................        31

                                           PART III
Item 10.                Directors and Executive Officers of the Registrant..........        31
Item 11.                Executive Compensation......................................        31
Item 12.                Security Ownership of Certain Beneficial Owners and
                        Management..................................................        31
Item 13.                Certain Relationships and Related Transactions..............        31

                                           PART IV
Item 14.                Exhibits, Financial Statement Schedules and Reports on Form
                        8-K.........................................................        31
SIGNATURES..........................................................................        33
</TABLE>

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--Termination of the Trust,"
"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 Company ("Pioneer") 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. 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.
<PAGE>
                                     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, The Chase
Manhattan Bank (the "Trustee"), 712 Main Street, Houston, Texas 77002. The
telephone number of the Trust is 1-800-852-1422.

    The principal asset of the Trust consists of a 99.99% interest in the Mesa
Offshore Royalty Partnership (the "Partnership"). The Trust was created on
December 28, 1982, effective December 1, 1982, when Mesa Petroleum Co. conveyed
to the Partnership certain overriding royalty interests (collectively, the
"Royalty") carved out of Mesa Petroleum Co.'s existing working interests in ten
producing and non-producing oil and gas leases offshore Louisiana and Texas (the
"Royalty Properties"). The Partnership was formed for the purpose of receiving
and holding the Royalty, receiving the proceeds from the Royalty, paying the
liabilities and expenses of the Partnership and disbursing remaining revenues to
the Trustee and Mesa Offshore Management Co., the managing general partner of
the Partnership at that time, in accordance with their interests. Until
August 7, 1997, MESA Inc. owned and operated its assets through Mesa Operating
Co. ("Mesa"), the operator and the managing general partner of the Royalty
Properties. On August 7, 1997, MESA Inc. merged with and into Pioneer, formerly
a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum Company
merged with and into Pioneer Natural Resources USA, Inc. (successor to Mesa
Operating Co.), a wholly owned subsidiary of Pioneer ("PNR") (collectively, the
mergers are referred to herein as the "Merger"). Subsequent to the Merger,
Pioneer owns and operates its assets through PNR and is also the managing
general partner of the Partnership. As hereinafter used in this report, the term
PNR generally refers to the operator of the Royalty Properties, unless otherwise
indicated. See "Termination of the Trust" on page 5 of this Form 10-K for
additional information regarding PNR and the Trust.

    Units of beneficial interest ("units") in the Trust were issued on
December 28, 1982 to Mesa Petroleum Co. shareholders, who received one unit for
each share of Mesa Petroleum Co. common stock held. The units are listed on the
Pacific Exchange under the symbol "MOS". The Trust has also been advised by the
National Association of Securities Dealers Automated Quotation System that the
units are currently being traded on the OTC Bulletin Board under the symbol
"MOSH.OB."

    The terms of the Mesa Offshore Trust Indenture (the "Trust Indenture")
provide, among other things, that: (1) the Trust cannot acquire any asset other
than its interest in the Partnership and cannot engage in any business or
investment activity; (2) the Royalty can be sold in part or in total for cash
upon approval of the unitholders or upon termination of the Trust; (3) the
Trustee can establish cash reserves and borrow funds to pay liabilities of the
Trust and can pledge the assets of the Trust to secure payment of the borrowing;
(4) the Trustee will make quarterly distributions of cash available for
distribution to the unitholders in January, April, July and October of each
year; and (5) the Trust will terminate upon the first to occur of the following
events: (i) the total amount of cash received per year by the Trust for each of
three successive years commencing after December 31, 1987 is less than ten times
one-third of the total amount payable to the Trustee as compensation for such
three-year period (the "Termination Threshold") or (ii) a vote by holders of a
majority of the outstanding units in favor of termination. Amounts paid to the
Trustee as compensation were $137,000, $132,000 and $128,000, for the years
2000, 1999 and 1998, respectively. Upon termination of the Trust, the Trustee
will sell for cash all the assets held in the Trust estate and make a final
distribution to unitholders of any funds remaining after all Trust liabilities
have been satisfied.

    The terms of the First Amended and Restated Articles of General Partnership
of the Partnership (the "Partnership Agreement") provide that the Partnership
shall dissolve upon the occurrence of any of the following: (1) December 31,
2030; (2) the election of the Trustee to dissolve the Partnership;

                                       1
<PAGE>
(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 minerals as, if
and when produced from the Royalty Properties. See "Description of Royalty
Properties" on page 6 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 in the circumstances. See "Contracts" on
page 12 of this Form 10-K. The Trustee has no power or authority to exercise any
control over the operation of the Royalty Properties or the marketing of
production 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,
which 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.

                                       2
<PAGE>
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 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

    OWNERSHIP OF UNITS

    The federal income tax consequences to the unitholders of owning units
depend on whether the Trust is classifiable as a grantor trust, a non-grantor
trust, or a corporation. The Trustee reports on the basis that the Trust is a
grantor trust. Based on its recent audit policy, the Internal Revenue Service
("IRS") is expected to concur with such action. No IRS ruling has been received
with respect to the Trust, however, and no court case has been decided involving
identical facts and circumstances. It is possible, therefore, that the IRS will
assert on audit that the Trust is taxable as a corporation and that a court
might agree with that assertion.

    INCOME AND DEPLETION

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

                                       3
<PAGE>
    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 that acquired units after that date
are entitled to claim an allowance for percentage depletion with respect to
Royalty income attributable to these units to the extent that this allowance
exceeds cost depletion as computed for the relevant period.

    BACKUP WITHHOLDING

    Distributions from the Trust are generally subject to backup withholding at
a rate of 31% of these distributions. Backup withholding will not normally apply
to distributions to a unitholder, however, unless a 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 a unitholder is
incorrect.

    SALE OF UNITS

    Generally, except for recapture items, the sale, exchange or other
disposition of a unit will result in capital gain or loss measured by the
difference between the 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 to the extent of the intangible drilling and development costs incurred
with respect to the property and depletion claimed with respect to such property
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 exceeded one year as of the date of sale or
exchange. A long-term capital gains rate of 20% applies to most capital assets
sold 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
disposition.

    NON-U.S. UNITHOLDERS

    In general, a unitholder who is a nonresident alien individual or which is a
foreign corporation, each a "non-U.S. unitholder" for purposes of this
discussion, will be subject to tax on the gross income produced by the Royalty
at a rate equal to 30% (or lower treaty rate, if applicable). 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 Internal Revenue 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 Internal Revenue 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 owning greater than five percent
of the outstanding units are subject to United States federal income tax on the
gain on the disposition of their units. Non-U.S. unitholders owning five percent
or less of the outstanding units are not subject to United States federal income
tax on the gain on the disposition of their units.

                                       4
<PAGE>
    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 should consult with his own tax adviser as to the advisability of his
ownership of units.

    TAX-EXEMPT ORGANIZATIONS

    Investments in publicly traded partnerships are treated the same as
investments in other partnerships for purposes of the rules governing unrelated
business taxable income. 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 income. Tax-exempt unitholders
should consult their own tax advisors with respect to the treatment of royalty
income.

                            TERMINATION OF THE TRUST

    As discussed above under "Description of the Trust", the terms of the Mesa
Offshore Trust Indenture provide that the Trust will terminate upon the first to
occur of the following events: (1) 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 the Termination Threshold or (2) a vote by holders of a majority of
the outstanding units in favor of termination. Because the Trust will terminate
in the event the total amount of cash received per year by the Trust falls below
certain levels, it would be possible for the Trust to terminate even though some
of the Royalty Properties continued to have remaining productive lives. For
information regarding the estimated remaining life of each of the Royalty
Properties and the estimated future net revenues of the Trust based on
information provided by PNR, see pages 11 and 12 of this Form 10-K and Note 7 in
the Notes to Financial Statements included elsewhere in this Form 10-K. Upon
termination of the Trust, the Trustee will sell for cash all the assets held in
the Trust estate and make a final distribution to unitholders of any funds
remaining after all Trust liabilities have been satisfied. The discussion set
forth above is qualified in its entirety by reference to the Trust Indenture
itself, which is an exhibit to this Form 10-K and is available upon request from
the Trustee.

    In addition, in the event of a dissolution of the Partnership (which could
occur under the circumstances described above under "Description of the Trust")
and a subsequent winding up and termination thereof, the assets of the
Partnership (i.e., the Royalty interest) could either (1) be distributed in kind
ratably to the Managing General Partner and the Trustee or (2) be sold and the
proceeds thereof distributed ratably to the Managing General Partner and the
Trustee. In the event of a sale of the Royalty and a distribution of the cash
proceeds to the Trustee, the Trustee would make a final distribution to
unitholders of such cash proceeds plus any other cash held by the Trust after
the payment of or provision for all liabilities of the Trust, and the Trust
would be terminated.

    The December 31, 2000 reserve report prepared for the Partnership indicates
that Royalty income expected to be received by the Trust in 2003 and thereafter
could be below the Termination Threshold. The reserve report estimates that
future Royalty income to the Trust is approximately $10.1 million, while the
Termination Threshold for 2000 was approximately $1.3 million. Future Royalty
income in the reserve report was calculated using oil and natural gas prices in
effect at December 31, 2000 of $26.30 per barrel and $10.17 per Mcf,
respectively. Natural gas prices have declined significantly to approximately
$5.00 per Mcf in March 2001; consequently, future Royalty income would be
significantly reduced if calculated using March 2001 prices. It is therefore
possible, based on March 2001 estimated natural gas prices, (depending on the
timing of production, market conditions, success of future drilling activity, if
any, and other matters) that in 2002 and thereafter Royalty income received by
the Trust may be below the Termination Threshold. If Royalty income falls below
the Termination Threshold for three successive years, the Trust would terminate
pursuant to the terms discussed above. There are

                                       5
<PAGE>
numerous uncertainties inherent in estimating and projecting the quantity and
value of proved reserves for the Trust properties as many of the Trust
properties are nearing the end of their productive lives and are therefore
subject to unforeseen changes in production rates. As such, there can be no
assurance that Royalty income received by the Trust in 2002 or thereafter will
be above the Termination Threshold.

                       DESCRIPTION OF ROYALTY PROPERTIES

PRODUCING ACREAGE AND WELLS AS OF DECEMBER 31, 2000

<TABLE>
<CAPTION>
                                                                                           PRODUCING WELLS(1)
                                                                                -----------------------------------------
                                                            PRODUCING ACRES            GROSS                  NET
                                                          -------------------   -------------------   -------------------
PROPERTY                                                   GROSS      NET(2)      OIL        GAS        OIL        GAS
--------                                                  --------   --------   --------   --------   --------   --------
<S>                                                       <C>        <C>        <C>        <C>        <C>        <C>
Offshore Louisiana--
  South Marsh Island 155(3).............................    5,000      2,625       --         --         --         --
  South Marsh Island 156(3).............................    5,000      2,625       --         --         --         --
  West Delta 61.........................................    5,000      3,750       --          1         --         .1
  West Delta 62.........................................    5,000      3,750       --          1         --         .1
Offshore Texas--
  Brazos A-7............................................    5,760      2,160       --          1         --         .1
  Brazos A-39...........................................    5,760      2,160       --          1         --         .4
  Matagorda Island 624..................................    5,617      1,369       --          1         --         .3
                                                           ------     ------      ---        ---        ---        ---
    Total...............................................   37,137     18,439       --          5         --        1.0
                                                           ======     ======      ===        ===        ===        ===
</TABLE>

------------------------

(1) Dual completions are counted as one well. For information regarding wells
    producing at December 31, 2000, see "Net Proceeds, Production and Average
    Prices" on page 20 of this Form 10-K.

(2) Net Producing Acres are calculated by multiplying gross producing acres by
    the net Royalty interest (as defined by the Trust Indenture) attributable to
    the Trust for each property.

(3) Production on this property ceased in February 2000. PNR has informed the
    Trust that it has no current plans for additional drilling or recompletion
    on this property. See "Operational Review" on page 18 of this Form 10-K.

RESERVES

    A study of the proved oil and gas reserves attributable to the Partnership
as of December 31, 2000, has been made by PNR. The following letter (the
"Reserve Report") summarizes such reserve study. The Reserve Report reflects
estimated reserve quantities and future net revenue based upon estimates of the
future timing of actual production without regard to when received in cash by
the Trust, which differs from the manner in which the Trust recognizes and
accounts for its royalty income. For further information regarding the Net
Overriding Royalty Interest, the Basis of Accounting for the Trust and Reserves,
see Notes 2, 3 and 7, respectively, in the Notes to Financial Statements
contained in Item 8 of this Form 10-K.

                                       6
<PAGE>
                                     [LOGO]

February 20, 2001

MESA Offshore Trust
Chase Bank of Texas, N.A. (as Trustee)
Chase Tower, Suite 1150
600 Travis Street
Houston TX 77002

Ladies and Gentlemen:

Pursuant to your request, we have prepared estimates, as of December 31, 2000,
of the extent and value of the proved crude oil, condensate, natural gas
liquids, and natural gas reserves of certain properties subject to a net profits
interest owned by the Mesa Offshore Royalty Partnership, hereinafter referred to
as the "Partnership," a partnership owned 99.99 percent by the Mesa Offshore
Trust. The interest appraised is referred to herein as the "Partnership
Interest" and consists of a 90 percent net profits interest in ten Pioneer
Natural Resources USA, Inc. (hereinafter referred to as "Pioneer") leases
located in the Gulf of Mexico offshore from Louisiana and Texas. The ten
offshore leases subject to the net profits interest are hereinafter referred to
as the "Subject Properties." Three of these leases have been abandoned; reserves
of the remaining seven leases are reported herein.

The reserve estimates are based on a detailed study of the Subject Properties.
The method or combination of methods used in the study of each reservoir was
tempered by experience in the area, consideration of the stage of development of
the reservoir, and the quality and completeness of basic data.

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

In the preparation of this report, Pioneer has used internal information with
respect to property interests owned by the Partnership, production from such
properties, current costs of operation and development, current prices for
production, agreements relating to current and future operations and sale of
production, and various other information.

The development status shown herein represents the status applicable as of
December 31, 2000. Data available from wells drilled on the appraised properties
through December 31, 2000 was used in estimating gross ultimate recovery. Gross
production estimated to December 31, 2000, was deducted from gross ultimate
recovery to arrive at the estimates of gross reserves. In some fields, this
required that the production rates be estimated for a portion of 2000 since
production data for these properties was not available throughout 2000.

The reserve volumes and revenue values shown in this report for Partnership
Interest were estimated from projections of reserves and revenue attributable to
the combined interests consisting of the Partnership Interest and the retained
Pioneer Interest in the Subject Properties (Combined Interest). Net reserves
attributable to the Partnership Interest were estimated by allocating to the
Partnership a portion of the estimated combined net reserves of the Subject
Properties based on future revenue. Therefore, the estimated net reserves
attributable to the Partnership Interest will vary if different future price and
cost assumptions are used. While estimates of reserves attributable to the Trust
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 the
working interest owners and the Trust. The net profits overriding royalty
interest is not a working interest and the Trust does not own and is not
entitled to receive any specific volume of reserves from the Trust. The
quantities of reserves attributable to the Trust will be affected by future
changes in various economic factors utilized in estimating future gross and net
revenues from the Trust Properties. Therefore, the estimates of reserves set
forth in the Reserve Reports are to a large extent hypothetical and differ in
significant respects from estimates of reserves attributable to a working
interest.

                                       7
<PAGE>
MESA Offshore Trust
February 20, 2000
Page 2

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

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

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

    - Undeveloped - Reserves that are recoverable from additional wells yet to
      be drilled. Undeveloped reserves are those considered proved for
      production by reasonable geological interpretation of adequate subsurface
      control in reservoirs that are producing or proved by other wells but are
      not recoverable from existing wells. This classification of reserves
      requires drilling of additional wells, major deepening of existing wells,
      or installation of enhanced recovery or other facilities.

Estimates of the net proved reserves attributable to the Partnership Interest,
as of December 31, 1999, are as follows:

<TABLE>
<S>                                                           <C>
TOTAL, PROVED RESERVES (PDP+PNP):
    Natural Gas (Mcf).......................................  901,408
    Oil and Condensate (bbl)................................   36,961
    Natural Gas Liquids (bbl)...............................        0

PROVED DEVELOPED PRODUCING RESERVES (PDP)
    Natural Gas (Mcf).......................................  366,564
    Oil and Condensate (bbl)................................   20,971
    Natural Gas Liquids (bbl)...............................        0
</TABLE>

Revenue values attributable to the net proved reserves of the Partnership
Interest are expressed in terms of estimated future net revenue and present
worth of future net revenue. Future net revenue attributable to the Partnership
Interest was estimated monthly from a projection of the combined Pioneer and
Partnership future net revenue. Combined future net revenue values were
calculated by deducting operating expenses and capital costs from the future
gross revenue of the Combined Interest. The monthly values for the aggregate of
the Combined Interest in the Subject Properties were reduced by an overhead
charge, by a monthly amount necessary for Pioneer to accrue the abandonment
costs over the life of the properties, by the deficit balance as described below
from the previous month, and by the interest on that deficit balance when such
deficits occur. If the adjusted revenue resulting from this calculation was
negative, it was carried forward to the next month as a deficit balance. If the
adjusted revenue was greater than zero, it was multiplied by a factor of 90
percent to arrive at the future net revenue of the Partnership Interest. The
above calculations were made monthly in the aggregate for the Subject
Properties. Interest was charged

                                       8
<PAGE>
MESA Offshore Trust
February 20, 2000
Page 3

monthly on the net profits deficit balance (cost not recovered currently) at the
rate of 9.0 percent per year. As of December 31, 2000 the Partnership Interest
did not have a deficit balance.

Future oil and gas producing rates estimated for this report are based on
production rates considering the most recent figures available or, in certain
cases, are based on estimates tempered by Pioneer's experience in the area. The
rates used for future production are rates that Pioneer has determined are
within the capacity of the well or reservoir to produce.

Gas volumes shown herein are expressed at standard conditions of 60 degrees
Fahrenheit and a 15.025 pounds per square inch absolute. Condensate reserves
estimated herein are those to be obtained from normal separator recovery.

Revenue values in this report were estimated using current prices and costs.
Future prices were estimated using guidelines established by the Securities and
Exchange Commission and the Financial Accounting Standards Board.

The assumptions used for estimating future prices and costs are as follows:

    - Oil and Condensate Prices - Oil and condensate prices were held constant
      for the life of the properties.

    - Natural Gas Prices - Gas prices were held constant for the life of the
      properties.

    - Natural Gas Liquids Prices - Natural gas liquids prices were held constant
      for the life of the properties.

    - Operating and Capital Costs - Current estimates of operating costs were
      used for the life of the properties with no increases in the future based
      on inflation. Future capital expenditures were estimated using 2000 values
      and were not adjusted for inflation.

A summary of estimated revenue and costs attributable to the Combined Interest
in proved reserves and the future net revenue and present worth attributable to
the Partnership Interest, as of December 31, 1999 is as follows:

<TABLE>
<S>                                                           <C>
COMBINED INTEREST:
    Future Gross Revenue ($)................................   11,974,073
    Production and Ad Valorem Taxes ($).....................            0
    Operating Costs ($).....................................     (687,838)
    Capital Costs ($)(1)....................................  (10,141,335)
    Future Net Revenue ($)..................................    1,144,896

    Accrued Revenue for Abandonment Costs ($)...............   10,125,087
    Future Accrued Revenue for Abandonment Costs ($)........            0
    Cumulative Net Profits Deficit @ 12/31/00...............            0
    Revenue Subject to Net Profits Interest ($).............   11,269,983

PARTNERSHIP INTEREST:
    Future Net Revenue ($)(2)...............................   10,142,985
    Present Worth at 10 Percent ($).........................    8,775,865
</TABLE>

(1) Includes abandonment costs.

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

The information relating to estimated proved reserves, estimated future net
revenue from proved reserves, and present worth of estimated future net revenue
from proved reserves of oil, condensate, natural gas liquids, and gas contained
in this report has been prepared in accordance with Paragraphs 10-13, 15 and
30(a)-(b) of Statement of Financial Accounting Standards No. 69 (November 1982)
of the Financial Accounting Standards Board and Rules 4-10(a)(l)-(13) of
Regulation S-X and Rule 302(b) of Regulation S-K of the Securities and Exchange
Commission; provided, however, future income tax expenses have not been taken
into account in estimating the future net revenue and present worth values set
forth herein.

                                       9
<PAGE>
MESA Offshore Trust
February 20, 2000
Page 4

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

Submitted,

/s/ JOHN PETERS

John Peters

                                       10
<PAGE>
    There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures, including many factors beyond the control of the
producer. The preceding reserve data in the Reserve Report represent estimates
only and should not be construed as being exact. Reserve assessment is a
subjective process of estimating the recovery from underground accumulations of
gas and oil that cannot be measured in an exact way, and estimates of other
persons might differ materially from those of PNR. 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 Securities and Exchange
Commission (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, 2000.
These prices (having a weighted average of $26.30 per barrel and $10.17 per Mcf
as of December 31, 2000) were held constant over the estimated life of the
Royalty Properties. Such 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 2000 was $2.96 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 $24.04.

    The following is a summary of the estimated remaining life for each of the
Royalty Properties provided to the Trustee by PNR as of December 31, 2000. There
are numerous uncertainties present in estimating the remaining productive lives
for the Royalty Properties. The following summary represents an estimate only
and should not be construed as being exact. The estimated remaining productive
life of each property varies depending on the recoverable reserves and annual
production assumed by PNR. In addition, future economic and operating conditions
may cause significant changes in these estimates.

<TABLE>
<CAPTION>
PROPERTY                                             PRODUCTIVE LIFE(1)(2)
--------                                             ---------------------
<S>                                                  <C>
South Marsh Island 155/156(3)......................  0 years
West Delta 61/62...................................  6-7 years
Brazos A-7.........................................  3-4 years
Brazos A-39........................................  1-2 years
Matagorda Island 624...............................  2-3 years
</TABLE>

------------------------

(1) The Trust will terminate in the event the total amount of cash received per
    year by the Trust falls below certain levels. Accordingly, it would be
    possible for the Trust to terminate even though some of the Royalty
    Properties continued to have remaining productive lives. See "Termination of
    the Trust" on page 5 of this Form 10-K.

                                       11
<PAGE>
(2) Estimates of remaining lives may vary significantly from year to year.

(3) Production on this property ceased in February 2000. PNR has informed the
    Trust that it has no current plans for additional drilling or recompletion
    on this property. See "Operational Review" on page 18 of this Form 10-K.

    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 $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.

    Standardized measure at December 31, 2000 was calculated using a natural gas
price of $10.17 per Mcf. Natural gas prices have declined significantly to
approximately $5.00 per Mcf in March 2001; consequently, the discounted future
net cash flows would be significantly reduced if the standardized measure was
calculated using March 2001 prices.

PROCEEDS, PRODUCTION AND AVERAGE PRICES

    Reference is made to "Net Proceeds, Production and Average Prices" under
Item 7 of this Form 10-K.

                                   CONTRACTS

    GENERAL.  PNR has advised the Trust that during 2000 its offshore gas
production was marketed under short-term contracts at spot market prices
primarily to H&N, Limited. 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 2000 were generally higher than
spot market prices in 1999. Information regarding recent prices received for
production from the Royalty Properties is provided below.

       BRAZOS A-7 AND A-39. In March 2001, most of the gas from this property
       was being sold to H&N, Limited at an average price of $4.87 per MMBtu.

       MATAGORDA ISLAND 624. In March 2001, most of the gas from this property
       was being sold to H&N, Limited at an average price of $4.83 per MMBtu.

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 has been 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 1999 and 2000, 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. The annual
average wellhead price for natural gas peaked in 1984 at $2.66 per Mcf and
declined to $1.55 per Mcf in 1995. Annual wellhead prices generally increased
from 1995 to $2.32 per MCF in 1997, decreased to $1.94 in 1998, increased to
$2.08 per Mcf in 1999 and increased to $3.35 per Mcf in 2000, according to the
Natural Gas Monthly published by the Energy Information Administration of the
Department of Energy.

                                       12
<PAGE>
    The seasonal nature of demand for natural gas and its effects on sales
prices and production volumes may cause the amounts of cash distributions by the
Trust to vary substantially on a seasonal basis. Generally, production volumes
and prices are higher during the first and fourth quarters of each calendar year
due primarily to peak demand in these periods. Because of the time lag between
the date on which PNR receives payment for production from the Royalty
Properties and the date on which distributions are made to unitholders, the
seasonality that generally affects production volumes and prices is generally
reflected in distributions to unitholders in later periods.

COMPETITION

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

MARKETING OF LIQUIDS

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

                             REGULATION AND PRICES

GENERAL

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

OPERATING HAZARDS AND UNINSURED RISKS

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

FERC REGULATION

    In recent years, the FERC has required interstate pipeline companies to
"unbundle" their services. To the extent a pipeline company or its sales
affiliate makes gas sales as a merchant in the future, it does so pursuant to
private contracts in direct competition with all other sellers, such as PNR. In
recent years, the FERC also has pursued a number of other policy initiatives
which could significantly affect the marketing of natural gas. Several of these
initiatives are intended to enhance competition in natural gas markets, although
some, such as "spindowns" of gathering assets, may have the adverse effect of
increasing the cost of doing business on some in the industry. In 1996, the FERC
issued a

                                       13
<PAGE>
Statement of Policy regarding its jurisdiction under the NGA and Outer
Continental Shelf Lands Act ("OCSLA") over new natural gas facilities and
services on the Outer Continental Shelf ("OCS"). Generally, the FERC retained
its existing tests for determining the jurisdictional status of offshore
facilities, but eased the application of its jurisdiction over facilities in
water depths of 200 meters or more. Recently, in addition to the traditional
factors, the FERC has added another factor to be considered for purposes of
identifying the demarcation point between gathering and transportation on OCS
pipeline systems, i.e., whether the system contains a centralized aggregation
point where gas supplies are delivered by multiple small diameter lines for
aggregation and subsequent delivery onshore through a larger diameter pipeline.
On February 9, 2000, the FERC issued Order No. 637, which permits, and in some
cases requires, interstate natural gas pipelines to make certain changes to the
nature of interstate transportation services. In Order No. 637-A, the FERC made
certain clarifying adjustments to the regulations promulgated in Order No. 637.
In Order No. 637-B, the FERC denied all further requests for rehearing. Order
Nos. 637, ET SEQ. currently are pending judicial review. In addition to the
changes implemented through Order No. 637, the FERC has stated that it will
institute a review of its regulatory model in light of the changes in the
natural gas industry. On April 10, 2000, the FERC issued Order No. 639, which
established new regulations under the OCSLA applicable to natural gas pipelines
operating on the OCS. The new regulations require non-exempt OCS gas service
providers to file with the FERC information regarding their affiliations and the
rates and terms pursuant to which they provide service to each and every
shipper. The purpose of the reporting requirements is to assist FERC and
interested persons in determining whether OCS gas service providers are
complying with the open access and nondiscrimination requirements of the OCSLA
and enable shippers which are subject to discrimination and anti-competitive
practices to bring such practices to the FERC's attention and seek remedial
action. In Order No. 639-A, the FERC clarified and modified certain of the
regulations. Order Nos. 639 and 639-A are pending judicial review. As to all of
these recent FERC initiatives, PNR has advised the Trust that the on-going, or,
in some instances, preliminary evolving nature of these regulatory initiatives
makes it impossible at this time to predict their ultimate impact on the prices,
markets or terms of sale of natural gas related to the Trust.

STATE 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.

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

                                       14
<PAGE>
and result in increased operating costs for the Royalty Properties, as well as
the oil and gas industry in general. State initiatives to further regulate the
disposal of oil and gas wastes are also pending in certain states, and these
initiatives could have a similar impact on the Royalty Properties.

    From time to time, federal and state environmental agencies propose
regulations which could have a direct and material impact on PNR's operations.
For example, under the Oil Pollution Act of 1990, as amended by the Coast Guard
Authorization Act of 1996 (collectively, "OPA"), parties responsible for
offshore facilities must establish and maintain evidence of oil-spill financial
responsibility ("OSFR") for costs attributable to potential oil spills. OPA
requires a minimum of $35 million in OSFR for offshore facilities located on the
OCS. This amount is subject to upward regulatory adjustment up to $150 million.
Responsible parties for more than one offshore facility are required to provide
OSFR only for their offshore facility requiring the highest OSFR. In 1998, the
Minerals Management Service ("MMS") adopted regulations for establishing the
amount of OSFR required for particular facilities. The amount of OSFR increases
as the volume of a facility's worst-case oil spill increases. Accordingly, for
facilities with worst-case spills of less than 35,000 barrels, only $35 million
in OSFR is required; for worst-case spills of over 35,000 barrels, $70 million
is required; for worst-case spills of over 70,000 barrels, $105 million is
required; and for worst-case spills of over 105,000 barrels, $150 million is
required. In addition, all OSFR below $150 million remains subject to upward
regulatory adjustment if warranted by the particular operational, environmental,
human health or other risks involved with a facility. Under this regulation, PNR
is required to maintain $35 million in OSFR for its offshore facilities. PNR is
maintaining its OSFR in this amount by insurance. Although the working interest
owners have advised the Trust that current environmental regulation has had no
material adverse effect on the working interest owners' present method of
operations, the impact of the recently adopted regulatory changes, and of future
environmental regulatory developments such as stricter environmental regulation
and enforcement policies, cannot presently be quantified. By letter dated
November 9, 1995, PNR was advised by the MMS that it does not qualify for a
waiver from supplemental bond requirements and that PNR may be required to post
supplemental bonds covering its potential obligations with respect to offshore
operations. PNR executed a guaranty of abandonment liability (area wide) with
the MMS on April 26, 1996, in satisfaction of these obligations.

    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 withholds from the Trust a reserve to
cover these future abandonment and removal costs. See Note 7 in the Notes to
Financial Statements for amounts withheld as of December 31, 2000 and amounts to
be withheld in the future.

ITEM 2.  PROPERTIES.

    Reference is made to Item 1 of this Form 10-K.

ITEM 3.  LEGAL PROCEEDINGS.

    There are no pending legal proceedings to which the Trust is a party.

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 2000.

                                       15
<PAGE>
                                    PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER
  MATTERS.

    The units of beneficial interest of the Trust are traded on the Pacific
Exchange--ticker symbol MOS. The high and low sales prices and distributions per
unit for each quarter in the two years ended December 31, 2000 were as follows:

<TABLE>
<CAPTION>
                                                                  2000                                 1999
                                                   ----------------------------------   ----------------------------------
                                                                         DISTRIBUTION                         DISTRIBUTION
                                                     HIGH       LOW          PAID         HIGH       LOW          PAID
                                                   --------   --------   ------------   --------   --------   ------------
<S>                                                <C>        <C>        <C>            <C>        <C>        <C>
First Quarter....................................   $.234      $.031        $.0177       $.047      $.016        $   --
Second Quarter...................................   $.234      $.031        $.0064       $.125      $.016        $.0272
Third Quarter....................................   $.125      $.016        $.0058       $.109      $.047        $.0079
Fourth Quarter...................................   $.109      $.047        $.0199       $.125      $.016        $.0059
</TABLE>

    At March 23, 2001, the 71,980,216 units outstanding were held by 13,774
unitholders of record.

ITEM 6.  SELECTED FINANCIAL DATA.

<TABLE>
<CAPTION>
                                      2000         1999         1998          1997         1996
                                   ----------   ----------   -----------   ----------   -----------
<S>                                <C>          <C>          <C>           <C>          <C>
Royalty income...................  $3,909,836   $3,474,732   $ 1,683,664   $5,737,644   $    36,014
Distributable income.............  $3,586,711   $2,952,611   $ 1,487,139   $4,900,814   $        --
Distributable income per unit....  $    .0498   $    .0410   $     .0206   $    .0681   $        --
Excess cost carryforward.........  $       --   $       --   $(1,109,013)  $       --   $(3,149,598)
Total assets at year end.........  $3,463,972   $2,455,718   $ 1,915,901   $3,274,532   $ 2,602,742
</TABLE>

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
  OF OPERATIONS.

FINANCIAL REVIEW

    YEARS 2000 AND 1999

    Royalty income increased to $3,909,836 in 2000 as compared to $3,474,732 in
1999. Royalty income in 2000 included a revision to the Trust's interest in two
wells located at West Delta 62 that resulted in a one-time payment in 2000 of
$787,463. Royalty income in 1999 included a release of MMS royalty reserve of
$2,116,594 (discussed below). Excluding the one-time payment from West Delta 62
in 2000 and the release of the MMS royalty reserve in 1999, royalty income would
have increased to $3,122,373 as compared to $1,358,138 in 1999. The increase in
royalty income is primarily related to new production from the farmout agreement
on West Delta 61 entered into in late 1999 and increased natural gas and crude
oil, condensate and natural gas liquids average sale prices. Distributable
income increased to $3,586,711 ($.0498 per unit) in 2000 as compared to
$2,952,611 ($.0410 per unit) in 1999. General and administrative expense
decreased in 2000 as compared to 1999 due to the Trust's recovery of $140,500 in
1999 to replenish the Trust's expense reserve fund.

    Production volumes for natural gas decreased to 1,115,766 Mcf in 2000
compared with 1,123,322 Mcf in 1999. The decrease was due primarily to natural
production decline partially offset by production volumes from the West Delta 61
farmout agreement and 201,423 Mcf related to the revision of the Trust's
interest in two wells located at West Delta 62. The average sale price received
for natural gas in 2000 was $2.96 per Mcf compared with $2.09 per Mcf in 1999.

    Crude oil, condensate and natural gas liquids production volumes increased
to 76,184 barrels in 2000 compared with 23,655 barrels in 1999. The increase was
due primarily to new production from the farmout agreement on West Delta 61 and
a revision to the Trust's interest in a well located at West Delta 62. Excluding
the one-time volumes associated with West Delta 62 revision, crude oil,
condensate

                                       16
<PAGE>
and natural gas liquids production volumes were 57,908 barrels in 2000. The
average sale price in 2000 for crude oil, condensate and natural gas liquids was
$24.04 per barrel compared with $15.14 per barrel in 1999.

    YEARS 1999 AND 1998

    Royalty income was $3,474,732 in 1999 as compared to $1,683,664 in 1998. The
increase in Royalty income was primarily due to the release of amounts
previously withheld by Pioneer relating to potential liabilities for royalty
claims of approximately $3.1 million ($2.1 million net of cost carryforwards
existing at the time). Excluding this one-time payment from Pioneer, Royalty
income would have decreased in 1999 when compared to 1998 as a result of lower
production volumes and the recoupment of $1.0 million of capital cost
carryforwards existing at December 1998. See "Liquidity and Capital Resources".
Distributable income increased to $2,952,611 ($.0410 per unit) in 1999 as
compared to $1,487,139 ($.0206 per unit) distributable income in 1998. During
1999, the Trust recovered approximately $140,500 in administrative expenses paid
from the Trust's reserve fund during the 1998 period in which Royalty income was
not paid to the Trust, replenishing the Trust's expense reserve fund balance to
$2.0 million.

    Production volumes for natural gas decreased to 1,123,322 Mcf in 1999
compared with 1,277,464 Mcf in 1998. The decrease was due primarily to the
cessation of production from South Marsh Island 155 and 156 in the fourth
quarter of 1999, and natural production decline on Matagorda Island 624
partially offset by increased production at Brazos A-7 and A-39 and West Delta
61 and 62 due to the successful farmouts. See "Operational Review". The average
sale price received for natural gas in 1999 was $2.09 per Mcf as compared to
$2.31 per Mcf in 1998.

    Crude oil, condensate and natural gas liquids production volumes decreased
to 23,655 barrels in 1999 compared to 51,066 barrels in 1998 due to the
cessation of production from South Marsh Island 155 and 156 in the fourth
quarter of 1999. See "Operational Review." The average sale price in 1999 for
crude oil, condensate and natural gas liquids was $15.14 per barrel compared
with $13.03 per barrel in 1998.

    GENERAL

    From inception of the Trust on December 1, 1982 through December 31, 1987,
PNR, as working interest owner, spent $110 million ($99 million net to the
Trust) to explore and develop the Royalty Properties. No significant
expenditures regarding exploration and development were made during 1988, 1989
or 1990. Beginning in late 1991 and continuing in 1992, PNR spent $9.6 million
($8.7 million net to the Trust) on exploration and development. No significant
exploration and development expenditures were made in 1993 or 1994. PNR spent
$3.4 million ($1.2 million net to the Trust) on exploration and development
during 1995 and $21.9 million ($13.8 million net to the Trust) in 1996. PNR also
spent $2.9 million ($1.8 million net to the Trust) in 1997, $7.5 million
($746,000 net to the Trust) in 1998, $117,000 ($73,000 net to the Trust) in 1999
and $247,000 ($138,000 net to the Trust) in 2000. PNR does not anticipate any
significant capital expenditures on the Royalty Properties in the future.
However, PNR is evaluating some potential exploration prospects on certain
blocks owned in part by the Trust. Due to the limited financial capacity of the
Trust, PNR expects it will attempt to farm out the Trust's interest in the
blocks it believes may be produced economically, retaining an overriding royalty
interest for the Trust.

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.

                                       17
<PAGE>
    The Trust's source of cash is the Royalty income received from its share of
the net proceeds from the Royalty Properties. Reference is made to Note 7 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.

    The December 31, 2000 reserve report prepared for the Partnership indicates
that Royalty income expected to be received by the Trust in 2003 and thereafter
could be below the Termination Threshold. The reserve report estimates that
future Royalty income to the Trust is approximately $10.1 million while the
Termination Threshold for 2000 was approximately $1.3 million. Future Royalty
income in the reserve report was calculated using oil and natural gas price in
effect at December 31, 2000 of $26.30 per barrel and $10.17 per Mcf,
respectively. Natural gas prices have declined significantly to approximately
$5.00 per Mcf in March 2001; consequently, future Royalty income would be
significantly reduced if calculated using March 2001 prices. It is therefore
possible, based on March 2001 estimated natural gas prices, (depending on the
timing of production, market conditions, success of future drilling activity, if
any, and other matters) that in 2002 and thereafter Royalty income received by
the Trust may be below the Termination Threshold. If Royalty income falls below
the Termination Threshold for three successive years, the Trust would terminate
pursuant to the terms discussed above. There are numerous uncertainties inherent
in estimating and projecting the quantity and value of proved reserves for the
Trust properties as many of the Trust properties are nearing the end of their
productive lives and are therefore subject to unforeseen changes in production
rates. As such, there can be no assurance that Royalty income received by the
Trust in 2002 or thereafter will be above the Termination Threshold.

    During the mid-1980's, PNR withheld approximately $3.5 million
($3.1 million net to the Trust) as a reserve for potential liabilities for
royalty claims made by the MMS. The claims by the MMS included, among other
things, disputed transportation allowances attributable to the Trust's South
Marsh Island properties and payments received by PNR from purchasers as
settlements under gas purchase contracts. During 1998, PNR settled all known
claims with the MMS for $3.6 million ($3.2 million net to the Trust) which
significantly reduced the amount in the reserve. As of March 31, 1999, the
balance of the reserve, including accrued interest, was approximately
$3.4 million ($3.1 million net to the Trust). In May 1999, PNR determined that
this reserve was no longer necessary. Approximately $3.1 million was released to
the Trust, subject to the recovery of an approximate $1.0 million cost
carryforward, and was included, net of amounts used to replenish the reserve for
Trust expenses, in the second quarter of 1999 distribution.

OPERATIONAL REVIEW

    As discussed in Item 1 of this Form 10-K, PNR has advised the Trust that
during 2000, its offshore gas production was marketed under short-term contracts
at spot market prices primarily to H&N, Limited 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 significantly higher in 2000 than spot
market prices in 1999.

    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.

    The Brazos A-7 and A-39 blocks experienced a decrease in production due to
natural production decline. PNR farmed out a portion of the Brazos A-7 block to
Newfield Exploration Co. and

                                       18
<PAGE>
participated at a 10% working interest in the completion of an exploratory gas
well drilled in the second quarter of 1997. During the fourth quarter of 1998,
PNR incurred $7.35 million ($661,000 net to the Trust) of completion costs for
the Brazos A-7 No. B-1 (formerly named No. 5) well. As of June 30, 1999, the
cost carryforward resulting from the completion costs on the Brazos A-7 No. B-1
well, other capital expenditures and over distributions by PNR were recovered.
The No. B-1 well commenced production late in the fourth quarter of 1998 and is
currently producing at a rate of approximately 5.5 MMcf and 9 barrels of
condensate per day. PNR farmed out their interest and the Trust's interest in
one-fourth of the Brazos A-39 block to Shell Oil Company in late 2000 in return
for a 2% override (1.8% net to the Trust) in one-fourth of the Brazos A-39 block
farmed out and one-fourth of three surrounding blocks.

    The South Marsh Island 155 and 156 blocks ceased production in the first
quarter of 2000. Four workovers were performed in 1999 to attempt to restore
production. While two were successful in restoring production for a short
period, the wells ceased production in February 2000. PNR expects to begin
abandonment procedures in 2001.

    The West Delta 61 and 62 blocks experienced an increase in oil and natural
gas production in 2000 as compared to 1999 primarily due to new production from
farmout agreements and a revision to the Trust's interest in a well located at
West Delta 62. In portions of West Delta block 62, the Trust is receiving
Royalty income from this property pursuant to a farmout agreement with Walter
Oil and Gas Corporation. The interest in the farmout wells which is attributable
to the Trust, consists of a 7.5% net profits interest. The wells are currently
producing at a rate of 4 MMcf and 109 barrels of condensate per day. In West
Delta block 61, PNR farmed out portions of the block to Stone Energy Corporation
(formerly Basin Exploration), retaining a 12.5% (11.25% net to the Trust)
overriding royalty interest. The operator drilled 3 exploratory wells, 2 of
which were successful. The 2 successful wells began producing during the second
quarter of 1999 with one currently producing at a rate of 400 Mcf and 329
barrels of condensate per day.

    Matagorda Island 624 production decreased in 2000 as compared to 1999,
primarily due to natural production decline. Gross production for the block is
currently 669 Mcf per day and zero barrels of condensate per day as of
February 2001 compared to 1.1 MMcf per day and 14 barrels of condensate per day
as of March 2000.

                                       19
<PAGE>
            NET PROCEEDS, PRODUCTION AND AVERAGE PRICES (UNAUDITED)

<TABLE>
<CAPTION>
                                                                     SOUTH
                                                                     MARSH         WEST       MATAGORDA
                                                       BRAZOS      ISLAND 155      DELTA        ISLAND
                                                    A-7 AND A-39    AND 156      61 AND 62       624          TOTAL
                                                    ------------   ----------   -----------   ----------   -----------
<S>                                                 <C>            <C>          <C>           <C>          <C>
YEAR ENDED DECEMBER 31, 2000:
  90% of--
    Gross proceeds................................   $1,334,771    $  93,542    $ 3,480,392    $229,686    $ 5,138,391
  Less 90% of--
    Operating costs...............................     (351,210)    (239,010)      (294,441)   (115,434)    (1,000,095)
    Capital costs recovered.......................      (42,544)     (95,525)            --          --       (138,069)
    Accrual for future abandonment costs..........      (33,767)     (11,565)       (39,562)     (5,106)       (90,000)
                                                     ----------    ----------   -----------    --------    -----------
  Net Proceeds....................................   $  907,250    $(252,558)   $ 3,146,389    $109,146    $ 3,910,227
                                                     ==========    ==========   ===========    ========    ===========
Trust share of net proceeds (99.99%)..............                                                         $ 3,909,836
                                                                                                           ===========
90% of Production Volumes and Average Sales
  Prices:
  Crude oil, condensate and natural gas liquids
  (Bbls).                                                   969          593         73,413       1,209         76,184
                                                     ==========    ==========   ===========    ========    ===========
  Average sales price per Bbl.....................   $    26.49    $   26.48    $     23.93    $  27.64    $     24.04
                                                     ==========    ==========   ===========    ========    ===========
  Natural gas (Mcf)...............................      419,880       33,595        599,642      62,649      1,115,766
                                                     ==========    ==========   ===========    ========    ===========
  Average sales price per Mcf.....................   $     3.12    $    2.32    $      2.87    $   3.13    $      2.96
                                                     ==========    ==========   ===========    ========    ===========
Producing wells (gross)...........................            2            0              2           1              5
YEAR ENDED DECEMBER 31, 1999:
  90% of--
    Gross proceeds................................   $1,286,275    $  87,980    $ 1,030,851    $297,346    $ 2,702,452
    Release of MMS royalty reserve................           --    2,116,594             --          --      2,116,594
  Less 90% of--
    Operating costs...............................     (370,852)    (329,626)      (380,637)   (136,573)    (1,217,688)
    Capital costs recovered.......................       (2,057)     (65,300)            --      (5,625)       (72,982)
    Accrual for future abandonment costs and
      interest on cost carryforward...............      (11,727)     (34,796)        (5,848)       (925)       (53,296)
                                                     ----------    ----------   -----------    --------    -----------
  Net Proceeds....................................   $  901,639    $1,774,852   $   644,366    $154,223    $ 3,475,080
                                                     ==========    ==========   ===========    ========    ===========
Trust share of net proceeds (99.99%)..............                                                         $ 3,474,732
                                                                                                           ===========
90% of Production Volumes and Average Sales
  Prices:
  Crude oil, condensate and natural gas liquids
  (Bbls).                                                   604        7,519         13,181       2,351         23,655
                                                     ==========    ==========   ===========    ========    ===========
  Average sales price per Bbl.....................   $    18.94    $   10.94    $     17.59    $  13.87    $     15.14
                                                     ==========    ==========   ===========    ========    ===========
  Natural gas (Mcf)...............................      636,058       27,510        317,538     142,216      1,123,322
                                                     ==========    ==========   ===========    ========    ===========
  Average sales price per Mcf.....................   $     2.00    $    0.21    $      2.52    $   1.86    $      2.09
                                                     ==========    ==========   ===========    ========    ===========
Producing wells (gross)...........................            3            1              3           1              8
YEAR ENDED DECEMBER 31, 1998:
  90% of--
    Gross proceeds................................   $  872,631    $1,527,059   $   456,750    $761,902    $ 3,618,342
  Less 90% of--
    Operating costs...............................     (299,732)    (795,642)      (580,501)   (153,745)    (1,829,620)
    Capital costs recovered.......................           --      (23,007)            --      (1,883)       (24,890)
    Accrual for future abandonment costs and
      interest on cost carryforward...............      (46,908)      (5,999)       (23,392)     (3,701)       (80,000)
                                                     ----------    ----------   -----------    --------    -----------
  Net Proceeds
    (Excess Costs)................................   $  525,991    $ 702,411    $  (147,143)   $602,573    $ 1,683,832
                                                     ==========    ==========   ===========    ========    ===========
Trust share of net proceeds (99.99%)..............                                                         $ 1,683,664
                                                                                                           ===========
90% of Production Volumes and Average Sales
  Prices:
  Crude oil, condensate and natural gas liquids
  (Bbls).                                                 1,668       43,589          1,013       4,796         51,066
                                                     ==========    ==========   ===========    ========    ===========
Average sales price per Bbl.......................   $    11.04    $   12.53    $     13.09    $  18.24    $     13.03
                                                     ==========    ==========   ===========    ========    ===========
Natural gas (Mcf).................................      384,969      419,725        170,106     302,664      1,277,464
                                                     ==========    ==========   ===========    ========    ===========
Average sales price per Mcf.......................   $     2.22    $    2.34    $      2.61    $   2.23    $      2.31
                                                     ==========    ==========   ===========    ========    ===========
Producing wells (gross)...........................            4            2              3           1             10
</TABLE>

                                       20
<PAGE>
------------------------------

    - The amounts shown are for the Mesa Offshore Royalty Partnership.

    - Producing wells indicates the gross number of wells capable of production
      as of the end of the period.

    - Gross proceeds is based on actual production for a twelve-month period
      ending on October 31 of each year, respectively.

    - Capital costs recovered represent capital costs incurred during the
      current or prior period to the extent that such costs have been recovered
      by PNR from gross proceeds.

    - 1999 natural gas average sales price per Mcf for South Marsh Island 155 &
      156 includes transportation charges relating to 1998 sales volumes that
      were not billed to PNR until 1999.

    - The release of MMS royalty reserve included in the twelve months ended
      December 31, 1999 relates to a refund by PNR to the Trust of $3.1 million
      after settling all known disputes with the MMS involving Trust properties,
      reduced by the cost carryforward of $1.0 million that existed at the time
      of the refund (see "Liquidity Capital Resources" in Item 7: "Management's
      Discussion and Analysis of Financial Condition and Results of
      Operations").

    - West Delta 61 and 62 proceeds includes a one-time payment in 2000 of
      $787,463 for a revision to Trust's interest in wells located at West
      Delta 62.

                                       21
<PAGE>
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

                              MESA OFFSHORE TRUST
                       STATEMENTS OF DISTRIBUTABLE INCOME

<TABLE>
<CAPTION>
                                                                 YEARS ENDED DECEMBER 31,
                                                           ------------------------------------
                                                              2000         1999         1998
                                                           ----------   ----------   ----------
<S>                                                        <C>          <C>          <C>
Royalty income...........................................  $3,909,836   $3,474,732   $1,683,664
Interest income..........................................     133,461      100,935      121,430
General and administrative expense.......................    (456,586)    (623,056)    (317,955)
                                                           ----------   ----------   ----------
Distributable income.....................................  $3,586,711   $2,952,611   $1,487,139
                                                           ==========   ==========   ==========
Distributable income per unit............................  $   0.0498   $   0.0410   $   0.0206
                                                           ==========   ==========   ==========
</TABLE>

               STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<TABLE>
<CAPTION>
                                                                      DECEMBER 31,
                                                              -----------------------------
                                                                  2000            1999
                                                              -------------   -------------
<S>                                                           <C>             <C>
                           ASSETS
Cash and short-term investments.............................  $   3,427,324   $   2,394,446
Interest receivable.........................................         13,092          28,636
Net overriding royalty interest in oil and gas properties...    380,905,000     380,905,000
  Less: accumulated amortization............................   (380,881,444)   (380,872,364)
                                                              -------------   -------------
Total assets................................................  $   3,463,972   $   2,455,718
                                                              =============   =============
                LIABILITIES AND TRUST CORPUS
Reserve for trust expenses..................................  $   2,000,000   $   2,000,000
Distribution payable........................................      1,440,416         423,082
Trust corpus (71,980,216 units of beneficial interest
  authorized and outstanding)...............................         23,556          32,636
                                                              -------------   -------------
Total liabilities and trust corpus..........................  $   3,463,972   $   2,455,718
                                                              =============   =============
</TABLE>

                     STATEMENTS OF CHANGES IN TRUST CORPUS

<TABLE>
<CAPTION>
                                                                YEARS ENDED DECEMBER 31,
                                                         ---------------------------------------
                                                            2000          1999          1998
                                                         -----------   -----------   -----------
<S>                                                      <C>           <C>           <C>
Trust corpus, beginning of year........................  $    32,636   $    56,401   $   248,200
  Distributable income.................................    3,586,711     2,952,611     1,487,139
  Distributions to unitholders.........................   (3,586,711)   (2,952,611)   (1,487,139)
  Amortization of net overriding royalty interest......       (9,080)      (23,765)     (191,799)
                                                         -----------   -----------   -----------
Trust corpus, end of year..............................  $    23,556   $    32,636   $    56,401
                                                         ===========   ===========   ===========
</TABLE>

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

                                       22
<PAGE>
                              MESA OFFSHORE TRUST
                         NOTES TO FINANCIAL STATEMENTS

(1)  TRUST ORGANIZATION AND PROVISIONS

    THE TRUST

    The Mesa Offshore Trust (the "Trust") was created effective December 1,
1982. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership,
which was predecessor to MESA Inc., transferred to the Trust a 99.99% interest
in the Mesa Offshore Royalty Partnership (the "Partnership"). The Trust is an
independent trust administered by The Chase Manhattan Bank, as trustee (the
"Trustee") successor by merger.

    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 $137,000,
    $132,000 and $128,000 for the years 2000, 1999 and 1998, respectively. Upon
    termination of the Trust, the Trustee will sell for cash all the assets held
    in the Trust estate and make a final distribution to unitholders of any
    funds remaining after all Trust liabilities have been satisfied.

    THE PARTNERSHIP

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

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

                                       23
<PAGE>
                              MESA OFFSHORE TRUST
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(1)  TRUST ORGANIZATION AND PROVISIONS (CONTINUED)
    STATUS OF THE TRUST

    The December 31, 2000 reserve report prepared for the Partnership (See
Note 7) indicates that Royalty income expected to be received by the Trust in
2003 and thereafter could be at or near the Termination Threshold. The reserve
report estimates that future Royalty income to the Trust is approximately
$10.1 million while the Termination Threshold for 2000 was approximately
$1.3 million. Future Royalty income in the reserve report was calculated using
oil and natural gas prices in effect at December 31, 2000 of $26.30 per barrel
and $10.17 per Mcf, respectively. Natural gas prices have declined significantly
to approximately $5.00 per Mcf in March 2001; consequently, future Royalty
income would be significantly reduced if calculated using March 2001 prices. It
is therefore possible, based on March 2001 estimated natural gas prices,
(depending on the timing of production, market conditions, success of future
drilling activity, if any, and other matters) that in 2002 and thereafter
Royalty income received by the Trust may be below the Termination Threshold. If
Royalty income falls below the Termination Threshold for three successive years,
the Trust would terminate pursuant to the terms discussed above. There are
numerous uncertainties inherent in estimating and projecting the quantity and
value of proved reserves for the Trust properties as many of the Trust
properties are nearing the end of their productive lives and are therefore
subject to unforeseen changes in production rates. As such, there can be no
assurance that Royalty income received by the Trust in 2002 or thereafter will
be above the Termination Threshold.

(2)  NET OVERRIDING ROYALTY INTEREST

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

    The initial carrying value of the Royalty represented the net book value
assigned by PNR to the Royalty Properties at the date of transfer to the Trust.
Amortization of the Royalty, which is calculated on the basis of current royalty
income in relation to estimated future royalty income, is charged directly to
trust corpus since such amounts do not affect distributable income.

(3)  BASIS OF ACCOUNTING

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

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

        (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.

                                       24
<PAGE>
                              MESA OFFSHORE TRUST
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(3)  BASIS OF ACCOUNTING (CONTINUED)
    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 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.

(4)  DISTRIBUTIONS TO UNITHOLDERS

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

(5)  RELEASE OF MMS ROYALTY RESERVE

    During the mid-1980's, PNR withheld approximately $3.5 million
($3.1 million net to the Trust) as a reserve for potential liabilities for
royalty claims made by the Mineral Management Service ("MMS"). The claims by the
MMS included, among other things, disputed transportation allowances
attributable to the Trust's South Marsh Island properties and payments received
by PNR from purchasers as settlements under gas purchase contracts. During 1998,
PNR settled all known claims with the MMS for $3.6 million ($3.2 million net to
the Trust) which significantly reduced the amount in the reserve. The balance of
the reserve, including accrued interest, was approximately $3.4 million
($3.1 million net to the Trust). In May 1999, PNR determined that this reserve
was no longer necessary. Approximately $3.1 million was released to the Trust,
subject to the recovery of an approximate $1.0 million cost carryforward, and
was included, net of amounts used to replenish the reserve for Trust expenses,
in the second quarter of 1999 distribution.

(6)  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.

(7)  SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

    Estimates of the proved oil and gas reserves attributable to the Royalty as
of December 31, 2000, 1999 and 1998 are based on a report prepared by PNR. The
estimates were prepared in accordance with guidelines established by the
Securities and Exchange Commission (the "SEC"). Accordingly, the

                                       25
<PAGE>
                              MESA OFFSHORE TRUST
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(7)  SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) (CONTINUED)
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 costs and expenses
of the Trust, which are expected to approximate $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.

                                       26
<PAGE>
                              MESA OFFSHORE TRUST
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

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

    ESTIMATED QUANTITIES OF PROVED AND PROVED DEVELOPED RESERVES (UNAUDITED)

<TABLE>
<CAPTION>
                                                               OIL AND      NATURAL
                                                              CONDENSATE      GAS
                                                              ----------   ---------
                                                                (BBLS)       (MCF)
<S>                                                           <C>          <C>
Proved Reserves:
  December 31, 1997.........................................     70,117    2,464,682
    Revisions of previous estimates.........................    115,088     (615,111)
    Extensions, discoveries and other additions.............    241,200      984,112
    Production..............................................    (22,133)    (553,682)
                                                               --------    ---------
  December 31, 1998.........................................    404,272    2,280,001
    Revisions of previous estimates.........................   (322,875)    (712,697)
    Extensions, discoveries and other additions.............         --           --
    Production..............................................     (3,431)    (162,926)
                                                               --------    ---------
  December 31, 1999.........................................     77,966    1,404,378
    Revisions of previous estimates.........................        552      153,193
    Extensions, discoveries and other additions.............         --           --
    Production..............................................    (41,557)    (656,163)
                                                               --------    ---------
  December 31, 2000.........................................     36,961      901,408
                                                               ========    =========
Proved Developed Reserves:
  December 31, 1998.........................................      5,628      933,684
                                                               ========    =========
  December 31, 1999.........................................     64,424    1,041,961
                                                               ========    =========
  December 31, 2000.........................................     36,961      901,408
                                                               ========    =========
</TABLE>

------------------------

(See Notes on following page.)

                                       27
<PAGE>
                              MESA OFFSHORE TRUST
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(7)  SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) (CONTINUED)
               STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM
      PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)

<TABLE>
<CAPTION>
                                                                 DECEMBER 31,
                                                              -------------------
                                                                2000       1999
                                                              --------   --------
                                                                (IN THOUSANDS)
<S>                                                           <C>        <C>
Ninety percent of future gross proceeds.....................  $10,777     $6,376
Less ninety percent of--
  Future operating costs....................................     (619)    (1,179)
  Future capital costs, net of amounts previously accrued...      (15)      (425)
                                                              -------     ------
Future royalty income.......................................   10,143      4,772
Discount at 10% per annum...................................   (1,367)      (525)
                                                              -------     ------
Standardized measure of future royalty income from proved
  oil and gas reserves......................................  $ 8,776     $4,247
                                                              =======     ======
</TABLE>

       CHANGES IN THE STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM
      PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)

<TABLE>
<CAPTION>
                                                                 YEARS ENDED DECEMBER 31,
                                                              ------------------------------
                                                                2000       1999       1998
                                                              --------   --------   --------
                                                                      (IN THOUSANDS)
<S>                                                           <C>        <C>        <C>
Standardized measure at beginning of year...................  $ 4,247    $ 3,977    $ 1,884
                                                              -------    -------    -------
  Revisions of previous estimates...........................   (3,218)    (4,629)      (559)
  Net changes in prices and production costs................   10,444      4,893      1,188
  Extensions, discoveries and other additions...............       --         --      2,960
  Royalty income............................................   (3,122)      (392)    (1,684)
  Accretion of discount.....................................      425        398        188
                                                              -------    -------    -------
  Net changes in standardized measure.......................    4,529        270      2,093
                                                              -------    -------    -------
Standardized measure at end of year.........................  $ 8,776    $ 4,247    $ 3,977
                                                              =======    =======    =======
</TABLE>

------------------------

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

- The "Future capital costs, net of amounts previously accrued" at December 31,
  2000 includes, in thousands, $9,113 of future abandonment costs net of $9,113
  previously accrued by PNR.

- 1999 Royalty income reflected in the "Changes in the Standardized Measure of
  Future Royalty Income" excludes $3.1 million from the release of MMS royalty
  payments withheld from the Trust as such amounts were not reflected in the
  Partnership's reserve report.

- Standardized measure at December 31, 2000 was calculated using a natural gas
  price of $10.17 per Mcf. Natural gas prices have declined significantly to
  approximately $5.00 per Mcf in March 2001; consequently, the discounted future
  net cash flows would be significantly reduced if the standardized measure was
  calculated using March 2001 prices.

                                       28
<PAGE>
                              MESA OFFSHORE TRUST
                   NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(8)  SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
                                                            SUMMARIZED QUARTERLY RESULTS
                                                                 THREE MONTHS ENDED
                                                ----------------------------------------------------
                                                 MARCH 31     JUNE 30     SEPTEMBER 30   DECEMBER 31
                                                ----------   ----------   ------------   -----------
<S>                                             <C>          <C>          <C>            <C>
2000:
Royalty income................................  $1,314,423   $  622,981     $461,949     $1,510,483
Distributable income..........................  $1,270,695   $  459,085     $416,514     $1,440,417
Distributable income per unit.................  $    .0177   $    .0064     $  .0058     $    .0199

1999:
Royalty income................................  $       --   $2,288,525     $588,131     $  598,076
Distributable income..........................  $       --   $1,958,849     $570,680     $  423,082
Distributable income per unit.................  $       --   $    .0272     $  .0079     $    .0059
</TABLE>

                                       29
<PAGE>
                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO THE CHASE MANHATTAN BANK (TRUSTEE)
  AND THE UNITHOLDERS OF THE MESA OFFSHORE TRUST:

    We have audited the accompanying statements of assets, liabilities and trust
corpus of the Mesa Offshore Trust as of December 31, 2000 and 1999, and the
related statements of distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 2000. These financial
statements are the responsibility of the Trustee. Our responsibility is to
express an opinion on these financial statements based on our audits.

    We conducted our audits in accordance with auditing standards generally
accepted in the 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 management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

    As described in Note 3, these financial statements were prepared on the
basis of accounting, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States.

    In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of the Mesa
Offshore Trust as of December 31, 2000 and 1999, and its distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 2000, on the basis of accounting described in Note 3.

                                               ARTHUR ANDERSEN LLP

Houston, Texas
March 23, 2001

                                       30
<PAGE>
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE.

    None.

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

    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.

ITEM 11.  EXECUTIVE COMPENSATION.

    Not applicable.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

    (A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS. Not applicable.

    (B) SECURITY OWNERSHIP OF MANAGEMENT. Not applicable.

    (C) CHANGES IN CONTROL. Registrant knows of no arrangement, including the
       pledge of securities of the Registrant, the operation of which may at a
       subsequent date result in a change in control of the Registrant.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

    Not Applicable.

                                    PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

    (A)(1)FINANCIAL STATEMENTS

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

<TABLE>
<CAPTION>
                                                              PAGE IN THIS
                                                               FORM 10-K
                                                              ------------
<S>                                                           <C>
Statements of Distributable Income..........................       22
Statements of Assets, Liabilities and Trust Corpus..........       22
Statements of Changes in Trust Corpus.......................       22
Notes to Financial Statements...............................       23
Report of Independent Public Accountants....................       30
</TABLE>

------------------------

    (A)(2)SCHEDULES

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

                                       31
<PAGE>
    (A)(3)EXHIBITS

<TABLE>
<CAPTION>
                                                                    SEC FILE OR
                                                                    REGISTRATION      EXHIBIT
                                                                       NUMBER          NUMBER
                                                                    ------------      --------
<S>   <C>                                                           <C>               <C>
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)
</TABLE>

------------------------

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

(B) REPORTS ON FORM 8-K

    None.

                                       32
<PAGE>
                                   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.

<TABLE>
<S>                                                    <C>  <C>
                                                       MESA OFFSHORE TRUST

                                                       By   THE CHASE MANHATTAN BANK, TRUSTEE

                                                       By                /s/ PETE FOSTER
                                                            -----------------------------------------
                                                                           Pete Foster
                                                              SENIOR VICE PRESIDENT & TRUST OFFICER
</TABLE>

March 23, 2001

    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.

                                       33