<Page>
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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, 2001
</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.)
     JPMORGAN CHASE BANK, TRUSTEE                             78701
     INSTITUTIONAL TRUST SERVICES                           (Zip Code)
              700 LAVACA
             AUSTIN, TEXAS
    (Address of Principal Executive
               Offices)
</Table>

       REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 1-512-479-2562

          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>
              None                       None
</Table>

          SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
                          UNITS OF BENEFICIAL INTEREST
                                (Title of Class)

    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 22, 2002, of $.05 was approximately $3,599,011.

    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 25, 2002, 71,980,216 Units of Beneficial Interest in Mesa
Offshore Trust.

    Documents Incorporated By Reference: None.

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<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....................................         3
                        Termination of the Trust....................................         5
                        Description of Royalty Properties...........................         6
                        Contracts...................................................        12
                        Regulation and Prices.......................................        13
                        Principal Trust Risk Factors................................        15
Item 2.                 Properties..................................................        18
Item 3.                 Legal Proceedings...........................................        18
Item 4.                 Submission of Matters to a Vote of Security Holders.........        18

                                           PART II
Item 5.                 Market for the Registrant's Common Equity and Related
                        Unitholder Matters..........................................        19
Item 6.                 Selected Financial Data.....................................        19
Item 7.                 Management's Discussion and Analysis of Financial Condition
                        and Results of
                        Operations..................................................        19
                        Net Proceeds, Production and Average Prices (Unaudited).....        23
Item 8.                 Financial Statements and Supplementary Data.................        25
Item 9.                 Changes in and Disagreements with Accountants on Accounting
                        and Financial
                        Disclosure..................................................        34

                                           PART III
Item 10.                Directors and Executive Officers of the Registrant..........        34
Item 11.                Executive Compensation......................................        34
Item 12.                Security Ownership of Certain Beneficial Owners and
                        Management..................................................        34
Item 13.                Certain Relationships and Related Transactions..............        34

                                           PART IV
Item 14.                Exhibits, Financial Statement Schedules and Reports on Form
                        8-K.........................................................        34
SIGNATURES..........................................................................        36
</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. A consolidated summary description of
principal risk factors that could cause actual results to differ is also set
forth in this Form 10-K under "Business--Principal Trust Risk Factors." All
subsequent written and oral forward-looking statements attributable to the Trust
or persons acting on its behalf are expressly qualified in their entirety by the
Cautionary Statements.
<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, JPMorgan Chase
Bank (the "Trustee"), 700 Lavaca, Austin, Texas 78701. The telephone number of
the Trust is 512-479-2562. JPMorgan Chase Bank was formerly known as The Chase
Manhattan Bank and is the successor by mergers to the original name of the
Trustee, Texas Commerce Bank National Association.

    The 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 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 $116,000, $137,000 and $132,000, for the years
2001, 2000 and 1999, 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.

                                       2
<Page>
                            DESCRIPTION OF THE UNITS

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

DISTRIBUTIONS

    The Trustee determines for each month the amount of cash available for
distribution for such month. Such amount (the "Monthly Distribution Amount") is
equal to the excess, if any, of the cash distributed by the Partnership to the
Trust during such month, plus any other cash receipts of the Trust during such
month (other than interest earned on the Monthly Distribution Amount for any
other month), over the liabilities of the Trust paid during such month, and
adjusted for changes made by the Trustee during such month in any cash reserves
established for the payment of contingent or future obligations of the Trust.
The Monthly Distribution Amount for each month is payable to unitholders of
record on the monthly record date (the "Monthly Record Date"), which is the
close of business on the last business day of such month, or such later date as
the Trustee determines is required to comply with legal or stock exchange
requirements. However, to reduce the administrative expenses of the Trust, the
Trust Indenture provides that the Trustee does not distribute cash monthly, but
rather, during January, April, July and October of each year, distributes to
each person who was a unitholder of record on a Monthly Record Date during one
or more of the immediately preceding three months, the Monthly Distribution
Amount for the month or months that he was a unitholder of record, together with
interest earned on such Monthly Distribution Amount from the Monthly Record Date
to the payment date.

LIABILITY OF UNITHOLDERS

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

FEDERAL INCOME TAX MATTERS

    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.

                                       3
<Page>
    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.

    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 30% 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

                                       4
<Page>
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.

    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, 2001 reserve report prepared for the Partnership indicates
that Royalty income expected to be received by the Trust in 2002 and thereafter
could be below the Termination Threshold. The reserve report estimates that
future Royalty income to the Trust is approximately $1.6 million, while the
Termination Threshold for 2001 was approximately $1.3 million. Future Royalty
income in the reserve report was calculated using oil and natural gas spot
prices in effect at December 31, 2001 of $19.76 per barrel and $2.73 per Mcf,
respectively. Based on the current estimates of Royalty income and current
market conditions in 2002, the Trustee expects that Royalty income received by
the Trust will be below the Termination Threshold in 2002. In addition,
depending on the future price of oil and

                                       5
<Page>
natural gas, the timing of production, market conditions, success of future
drilling activity, if any, and other matters, the Royalty income received by the
Trust after 2002 may also 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.

                       DESCRIPTION OF ROYALTY PROPERTIES

PRODUCING ACREAGE AND WELLS AS OF DECEMBER 31, 2001

<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(3)--
  West Delta 61.........................................    5,000      3,750       --          2         --         .2
  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...............................................   27,137     13,189       --          6         --        1.1
                                                           ======     ======      ===        ===        ===        ===
</Table>

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

(1) Dual completions are counted as one well. For information regarding wells
    producing at December 31, 2001, see "Net Proceeds, Production and Average
    Prices" on page 23 of this Form 10-K. As of March 20, 2002, only the wells
    on Brazos A-7 and A-39 were producing, and the well on Matagorda Island 624
    was shut-in awaiting a recompletion. The wells at West Delta 61 were shut-in
    for platform maintenance and the well at West Delta 62 has ceased
    production.

(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) All wells on South Marsh Island 155 and 156 leases were plugged and
    abandoned in 2001. PNR expects to abandon the platform for these two
    properties in 2002.

RESERVES

    A study of the proved oil and gas reserves attributable to the Partnership
as of December 31, 2001, 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>


                              [PIONEER LETTERHEAD]


   March 13, 2002



   MESA Offshore Trust
   JPMorgan Chase Bank (as Trustee)
   700 Lavaca Street, 5th Floor
   Austin, Texas 78701-3102

   Ladies and Gentlemen:

   Pursuant to your request, we have prepared estimates, as of December 31,
   2001, 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 seven offshore leases subject to the net profits interest are
   hereinafter referred to as the "Subject Properties." Two of these leases are
   currently being abandoned; reserves of the remaining five 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, 2001. Data available from wells drilled on the appraised
   properties through December 31, 2001 was used in estimating gross ultimate
   recovery. Gross production estimated to December 31, 2001, 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
   2001 since production data for these properties was not available throughout
   2001.

   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.



                                       7
<PAGE>

   MESA Offshore Trust
   March 13, 2002
   Page 2


   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.

   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:

   o  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.

   o  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.

   o  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, 2001, are as follows:


             TOTAL, PROVED RESERVES (PDP+PNP):
                  Natural Gas (Mcf) .....................    492,205
                  Oil and Condensate (bbl)  .............     13,174
                  Natural Gas Liquids (bbl)    ..........          0

             PROVED DEVELOPED PRODUCING RESERVES (PDP)
                  Natural Gas (Mcf)   ...................     66,502
                  Oil and Condensate (bbl)    ...........      1,773
                  Natural Gas Liquids (bbl)    ..........          0



                                       8
<PAGE>

   MESA Offshore Trust
   March 13, 2002
   Page 3



   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 monthly on the net
   profits deficit balance (cost not recovered currently) at the rate of 9.0
   percent per year. As of December 31, 2001 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:

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

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

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

        o   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 2001 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, 2001 is as
   follows:



                                       9

<PAGE>

   MESA Offshore Trust
   March 13, 2002
   Page 4


COMBINED INTEREST:
      Future Gross Revenue ($) ..................................    3,367,720
      Production and Ad Valorem Taxes ($) .......................            0
      Operating Costs ($) .......................................   (1,578,348)
      Capital Costs ($)1.........................................   (9,275,112)
      Future Net Revenue ($) ....................................   (7,485,740)

      Accrued Revenue for Abandonment Costs ($) .................    9,249,113
      Future Accrued Revenue for Abandonment Costs($) ...........            0
      Cumulative Net Profits Deficit @ 12/31/00 .................            0
      Revenue Subject to Net Profits Interest ($) ...............    1,763,373


PARTNERSHIP INTEREST:
      Future Net Revenue ($)2 ...................................    1,587,032
      Present Worth at 10 Percent ($) ...........................    1,249,872

   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.

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, 2001.
These prices (having a weighted average year end price of $19.22 per barrel and
$2.71 per Mcf as of December 31, 2001) were held constant over the estimated
life of the Royalty Properties. These prices were influenced by seasonal demand
for natural gas and may not be the most appropriate or representative prices to
use for estimating future revenues or related reserve data. The average price of
natural gas sold from the Royalty Properties during 2001 was $4.96 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 $26.19.

    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, 2001. 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>
West Delta 61/62...................................  7-8 years
Brazos A-7.........................................  2-3 years
Brazos A-39........................................  2-3 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.

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

                                       11
<Page>
    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.

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 2001 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 2001 were generally higher than spot market
prices in 2000. Information regarding recent prices received for production from
the Royalty Properties is provided below.

       BRAZOS A-7 AND A-39. In March 2002, most of the gas from this property
       was being sold to H&N, Limited at an average price of $2.20 per MMBtu.

       MATAGORDA ISLAND 624. In March 2002, most of the gas from this property
       was being sold to H&N, Limited at an average price of $2.08 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 was affected generally by a surplus in natural gas
deliverability in comparison to demand. Demand for gas declined during this
period due to a number of factors including the implementation of energy
conservation programs, a shift in economic activity away from energy intensive
industries and competition from alternative fuel sources such as residual fuel
oil, coal and nuclear energy. In late 2000 and early 2001, 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, increased to $3.69 per Mcf in 2000, then increased again
to $4.12 per Mcf in 2001, according to the Natural Gas Monthly published by the
Energy Information Administration of the Department of Energy.

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

                                       12
<Page>
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 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

                                       13
<Page>
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 stated 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. On January 11, 2002, the
United States District Court for the District of Columbia ruled that the
reporting requirements adopted in Order No. 639, ET. SEQ., were in excess of the
FERC's statutory authority and on this basis enjoined enforcement of the
regulations. WILLIAMS COMPANIES, INC. V FERC, C.A. No. 01-1976 (RCL) (Order and
Memorandum Opinion issued January 11, 2002). The decision has been appealed by
the FERC and certain other parties to the United States Court of Appeals for the
District of Columbia Circuit. WILLIAMS COMPANIES, ET. AL. V. FERC (Case No.
02-5056). 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 and result
in increased operating costs for the Royalty Properties, as well as the oil and
gas industry in

                                       14
<Page>
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, 2001 and amounts to
be withheld in the future.

                          PRINCIPAL TRUST RISK FACTORS

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

NATURAL GAS AND OIL PRICES FLUCTUATE DUE TO A NUMBER OF FACTORS, AND LOWER
PRICES WILL REDUCE NET PROCEEDS AVAILABLE TO THE TRUST AND DISTRIBUTIONS TO
TRUST UNITHOLDERS.

    The Trust's quarterly distributions are highly dependent upon the prices
realized from the sale of natural gas and oil. Natural gas and oil prices can
fluctuate widely on a month-to-month basis in

                                       15
<Page>
response to a variety of factors that are beyond the control of the Trust and
the working interest owners. Factors that contribute to price fluctuation
include, among others:

       - political conditions in the Middle East;

       - worldwide economic conditions;

       - weather conditions;

       - the supply and price of foreign natural gas and oil;

       - the level of consumer demand;

       - the price and availability of alternative fuels;

       - the proximity to, and capacity of, transportation facilities; and

       - the effect of worldwide energy conservation measures.

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

    Lower natural gas and oil prices may reduce the amount of natural gas that
is economic to produce and reduce net profits available to the Trust. The
volatility of energy prices reduces the predictability of future cash
distributions to unitholders. Substantially all of the natural gas and natural
gas liquids produced from the Royalty Properties is being sold on the spot
market or under short-term contracts.

INCREASED PRODUCTION AND DEVELOPMENT COSTS FOR THE ROYALTY WILL RESULT IN
DECREASED TRUST DISTRIBUTIONS.

    Production and development costs attributable to the Royalty are deducted in
the calculation of the Trust's share of net proceeds. Accordingly, higher or
lower production and development costs, without concurrent increases in
revenues, directly decrease or increase the amount received by the Trust for the
Royalty.

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

TRUST RESERVE ESTIMATES DEPEND ON MANY ASSUMPTIONS THAT MAY PROVE TO BE
INACCURATE, WHICH COULD CAUSE BOTH ESTIMATES RESERVES AND ESTIMATED FUTURE
REVENUES TO BE TOO HIGH.

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

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

       - the assumed effect of governmental regulation; and

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

Changes in these assumptions can materially change reserve estimates.

    The reserve quantities attributable to the Royalty and revenues are based on
estimates of reserves and revenues for the underlying properties. The method of
allocating a portion of those reserves to the

                                       16
<Page>
Trust is complicated because the Trust holds an interest, indirectly through the
Partnership, in the Royalty and does not own a specific percentage of the
natural gas reserves.

ESTIMATES AND ACCRUALS OF ABANDONMENT COSTS BY PNR MAY BE GREATER OR LESSER THAN
FUTURE ESTIMATED OR ACTUAL COSTS.

    As discussed in Note 7 to the Notes to Financial Statements, at December 31,
2001 PNR has accrued approximately $8.3 million for future abandonment costs. To
the extent future estimated or actual abandonment costs exceed this accrual, PNR
would be entitled to accrue and withhold such amounts from payments with respect
to the Royalty. Similarly, to the extent future estimated or actual abandonment
costs are less than this accrual, PNR may release such amounts. Only unitholders
at the time of any such release and distribution would be entitled to the
distribution by the Trust.

OPERATING RISKS FOR THE WORKING INTEREST OWNERS' INTERESTS IN THE ROYALTY
PROPERTIES CAN ADVERSELY AFFECT TRUST DISTRIBUTIONS.

    The occurrence of drilling, production or transportation accidents at any of
the Royalty Properties will reduce Trust distributions by the amount of
uninsured costs. These accidents may result in personal injuries, property
damage, damage to productive formations or equipment and environmental damages.
Any uninsured costs would be deducted as a production cost in calculating net
proceeds payable to the Trust.

NEITHER THE TRUSTEE, THE TRUST NOR ITS UNITHOLDERS CONTROL THE OPERATION OR
DEVELOPMENT OF THE ROYALTY PROPERTIES AND HAVE LITTLE INFLUENCE OVER OPERATION
OR DEVELOPMENT.

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

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

THE OWNER OF ANY ROYALTY PROPERTY MAY ABANDON ANY PROPERTY, TERMINATING THE
RELATED ROYALTY.

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

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

THE ROYALTY CAN BE SOLD AND THE TRUST CAN BE TERMINATED.

    The Trust will be terminated and the Trustee must sell the Royalty if
holders of a majority of the units of beneficial interest of the Trust approve
the sale or vote to terminate the Trust, or if the total amount of cash received
per year by the Trust for each of three consecutive years is less than the
Termination Threshold. Following any such termination and liquidation, the net
proceeds of any sale

                                       17
<Page>
will be distributed to the unitholders and unitholders will receive no further
distributions from the Trust. We cannot assure you that any such sale will be on
terms acceptable to all unitholders. As discussed in Item 1 of this Form 10-K
under "Business--Termination of the Trust," the Trustee currently expects (based
on current estimates of Royalty income and current market conditions) that
Royalty income received by the Trust will be below the Termination Threshold in
2002.

TRUST ASSETS ARE DEPLETING ASSETS AND, IF THE WORKING INTEREST OWNERS OR OTHER
OPERATORS OF THE ROYALTY PROPERTIES DO NOT PERFORM ADDITIONAL DEVELOPMENT
PROJECTS, THE ASSETS MAY DEPLETE FASTER THAN EXPECTED.

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

UNITHOLDERS HAVE LIMITED VOTING RIGHTS.

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

UNITHOLDERS HAVE LIMITED ABILITY TO ENFORCE THE TRUST'S RIGHTS AGAINST THE
CURRENT OR FUTURE OWNERS OF THE ROYALTY PROPERTIES.

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

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 2001.

                                       18
<Page>
                                    PART II

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

    The units of beneficial interest of the Trust were delisted from the Pacific
Exchange effective May 18, 2001. The Trust units are currently eligible for
trading on the OTC Bulletin Board under ticker symbol MOSH. There was no
distribution of income for the month of December 2001, due to a deficit balance
related to production revenue. The high and low sales prices and distributions
per unit for each quarter in the two years ended December 31, 2001 were as
follows:

<Table>
<Caption>
                                                                  2001                                 2000
                                                   ----------------------------------   ----------------------------------
                                                                         DISTRIBUTION                         DISTRIBUTION
                                                     HIGH       LOW          PAID         HIGH       LOW          PAID
                                                   --------   --------   ------------   --------   --------   ------------
<S>                                                <C>        <C>        <C>            <C>        <C>        <C>
First Quarter....................................   $0.13      $0.06       $0.0084       $.234      $.031        $.0177
Second Quarter...................................   $0.13      $0.08       $0.0057       $.234      $.031        $.0064
Third Quarter....................................   $0.10      $0.06       $0.0034       $.125      $.016        $.0058
Fourth Quarter...................................   $0.10      $0.05       $0.0020       $.109      $.047        $.0199
</Table>

    At March 19, 2002, the 71,980,216 units outstanding were held by 12,706
unitholders of record.

ITEM 6.  SELECTED FINANCIAL DATA.

<Table>
<Caption>
                                     2001         2000         1999          1998          1997
                                  ----------   ----------   -----------   -----------   -----------
<S>                               <C>          <C>          <C>           <C>           <C>
Royalty income..................  $1,772,595   $3,909,836   $ 3,474,732   $ 1,683,664   $ 5,737,644
Distributable income............  $1,401,106   $3,586,711   $ 2,952,611   $ 1,487,139   $ 4,900,814
Distributable income per unit...  $   0.0195   $    .0498   $     .0410   $     .0206   $     .0681
Excess cost carryforward........  $       --   $       --   $        --   $(1,109,013)  $        --
Total assets at year end........  $2,153,070   $3,463,972   $ 2,455,718   $ 1,915,901   $ 3,274,532
</Table>

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

FINANCIAL REVIEW

    YEARS 2001 AND 2000

    Royalty income decreased to $1,772,595 in 2001 as compared to $3,909,836 in
2000. The decrease in Royalty Income is primarily due to lower production at
Brazos A-7 and A-39 and West Delta 61 and 62, which was partially offset by an
increase in price. Royalty income in 2000 also included a revision to the
Trust's interest in two wells at West Delta 62 that resulted in a one-time
payment to the trust of $787,463. Distributable income decreased to $1,401,106
($.0195 per unit) in 2001 as compared to $3,586,711 ($.0498 per unit) in 2000.
General and administrative expense increased to $459,027 in 2001 as compared to
$456,586 in 2000.

    Production volumes for natural gas decreased to 457,918 Mcf in 2001 compared
with 1,115,766 Mcf in 2000 primarily due to natural production decline at Brazos
A-7 and A-39 and West Delta 61 and 62 and a 2000 upward revision of the Trust's
interest in West Delta 62 of 201,423 Mcf of natural gas. The average sale price
received for natural gas in 2001 was $4.96 per Mcf compared with $2.96 per Mcf
in 2000. Crude oil, condensate and natural gas liquids production volumes
decreased to 17,280 barrels in 2001 compared with 76,184 barrels in 2000. The
decrease was due primarily to natural production decline at West Delta 61 and 62
and a 2000 upward revision of the Trust's interest in West Delta 62 of 18,276
barrels of crude oil, condensate and natural gas liquids. The average sale price
in 2001 for crude oil, condensate and natural gas liquids was $26.19 per barrel
compared with $24.04 per barrel in 2000.

                                       19
<Page>
    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 in "--Liquidity and Capital Resources"). 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 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.

    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, $247,000 ($138,000 net to the Trust) in 2000 and $162,000 ($71,000 net to
the Trust) in 2001. 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.

    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

                                       20
<Page>
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, 2001 reserve report prepared for the Partnership indicates
that Royalty income expected to be received by the Trust in 2002 and thereafter
could be below the Termination Threshold. The reserve report estimates that
future Royalty income to the Trust is approximately $1.6 million while the
Termination Threshold for 2001 was approximately $1.3 million. Future Royalty
income in the reserve report was calculated using oil and natural gas spot
prices in effect at December 31, 2001 of $19.76 per barrel and $2.73 per Mcf,
respectively. Based on the current estimates of Royalty income and current
market conditions, the Trustee expects that Royalty income received by the Trust
will be below the Termination Threshold in 2002. In addition, depending on the
future price of oil and natural gas, the timing of production, market
conditions, success of future drilling activity, if any, and other matters the
Royalty income received by the Trust after 2002 may also 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 2001, 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 on the average higher in 2001 than spot
market prices in 2000.

    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 in 2001
due to natural production decline. The No. A-4 well in the Brazos A-7 block
ceased production in late 2001 leaving only the Newfield Exploration Company
well producing on that block as of year end. It is currently producing at a rate
of 2.6 MMcf of natural gas per day with no associated condensate. In addition,
there is one well producing on Brazos A-39 block currently at 1.0 MMcf of
natural gas per day with no

                                       21
<Page>
associated condensate. 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% (1.8% net to the Trust) override in the one-fourth of the Brazos A-39
block farmed out and one-fourth of three surrounding blocks. PNR has informed
the Trustee that it is also investigating some exploration prospects on these
blocks, but there can be no assurance that these will be drilled.

    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 commenced abandonment
procedures during the second quarter of 2001. These procedures are expected to
be completed in the summer of 2002. The leases have expired and the MMS has
granted an extension to abandon the lease to PNR due to a pipeline company not
being able to abandon its pipeline timely.

    The West Delta 61 and 62 blocks experienced a decrease in production in 2001
due to a one-time revision in the Walter Oil and Gas Corporation ("Walter")
operated well that was paid to the Trust in 2000 as well as natural production
decline. PNR has studied these leases and has no prospects identified. As such,
plans are underway to abandon the PNR operated platform and associated wells
that are no longer producing. In West Delta 62, the Trust is receiving Royalty
income pursuant to a farmout agreement with Walter. However, the well ceased
production subsequent to year end and Walter served notice that it intends to
plug and abandon this well. In West Delta 61, PNR farmed out portions of the
block to Stone Energy Corporation ("Stone"), retaining a 12.5% (11.25% net to
the Trust) overriding royalty interest. Stone currently has these two wells
shut-in for a conversion from a manned platform to an unmanned platform, but
prior to being shut-in, the wells were producing at a combined rate of .3 MMcf
of natural gas and 365 barrels of condensate per day. It is anticipated that
they will come back on line at that rate when the conversion is complete.

    The Matagorda 624 block experienced increased production in 2001 as compared
to 2000 primarily due to a workover that was performed in the second quarter of
2001. The well has recently ceased production and another workover is planned
for late March 2002 to re-establish production. This is the last behind pipe
reserves that PNR has identified and there are no prospects on this block.
Therefore, once this reservoir is depleted in this last producing well, plugging
and abandonment procedures will likely be the next operation on this block.

                                       22
<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, 2001:
  90% of--
    Gross proceeds................................   $1,308,156    $  (5,571)   $ 1,019,607    $403,876    $ 2,726,068
  Less 90% of--
    Operating costs...............................     (312,391)    (131,470)      (253,502)   (175,104)      (872,467)
    Capital costs recovered.......................      (48,703)      (2,124)            --     (20,002)       (70,829)
    Accrual for future abandonment costs and
      interest on cost carryforward...............       (6,106)          --         (3,822)        (72)       (10,000)
                                                     ----------    ----------   -----------    --------    -----------
  Net Proceeds....................................   $  940,956    $(139,165)   $   762,283    $208,698    $ 1,772,772
                                                     ==========    ==========   ===========    ========    ===========
Trust share of net proceeds (99.99%)..............                                                         $ 1,772,595
                                                                                                           ===========
90% of Production Volumes and Average Sales
  Prices:
  Crude oil, condensate and natural gas liquids
  (Bbls).                                                   238           --         15,673       1,369         17,280
                                                     ==========    ==========   ===========    ========    ===========
Average sales price per Bbl.......................   $    26.76    $      --    $     26.25    $  25.42    $     26.19
                                                     ==========    ==========   ===========    ========    ===========
Natural gas (Mcf).................................      254,607           89        112,995      90,227        457,918
                                                     ==========    ==========   ===========    ========    ===========
Average sales price per Mcf.......................   $     5.11    $      --    $      5.38    $   4.09    $      4.96
                                                     ==========    ==========   ===========    ========    ===========
Producing wells (gross)...........................            2           --              3           1              6
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 and
      interest on cost carryforward...............      (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           --              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
</Table>

                                       23
<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 and production includes a one-time payment
      in 2000 of $787,463 for a revision to Trust's interest in wells located at
      West Delta 62.
    - As of March 20, 2002, only the wells on Brazos A-7 and A-39 were
      producing.

                                       24
<Page>
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

                              MESA OFFSHORE TRUST
                       STATEMENTS OF DISTRIBUTABLE INCOME

<Table>
<Caption>
                                                                 YEARS ENDED DECEMBER 31,
                                                           ------------------------------------
                                                              2001         2000         1999
                                                           ----------   ----------   ----------
<S>                                                        <C>          <C>          <C>
Royalty income...........................................  $1,772,595   $3,909,836   $3,474,732
Interest income..........................................      87,538      133,461      100,935
General and administrative expenses......................    (459,027)    (456,586)    (623,056)
                                                           ----------   ----------   ----------
Distributable income.....................................  $1,401,106   $3,586,711   $2,952,611
                                                           ==========   ==========   ==========
Distributable income per unit............................  $   0.0195   $   0.0498   $   0.0410
                                                           ==========   ==========   ==========
</Table>

               STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<Table>
<Caption>
                                                                      DECEMBER 31,
                                                              -----------------------------
                                                                  2001            2000
                                                              -------------   -------------
<S>                                                           <C>             <C>
                           ASSETS
Cash and short-term investments.............................  $   2,136,891   $   3,427,324
Interest receivable.........................................          5,052          13,092
Net overriding royalty interest in oil and gas properties...    380,905,000     380,905,000
  Less: accumulated amortization............................   (380,893,873)   (380,881,444)
                                                              -------------   -------------
Total assets................................................  $   2,153,070   $   3,463,972
                                                              =============   =============
                LIABILITIES AND TRUST CORPUS
Reserve for trust expenses..................................  $   2,000,000   $   2,000,000
Distributions payable.......................................        141,943       1,440,416
Trust corpus (71,980,216 units of beneficial interest
  authorized and outstanding)...............................         11,127          23,556
                                                              -------------   -------------
Total liabilities and trust corpus..........................  $   2,153,070   $   3,463,972
                                                              =============   =============
</Table>

                     STATEMENTS OF CHANGES IN TRUST CORPUS

<Table>
<Caption>
                                                                YEARS ENDED DECEMBER 31,
                                                         ---------------------------------------
                                                            2001          2000          1999
                                                         -----------   -----------   -----------
<S>                                                      <C>           <C>           <C>
Trust corpus, beginning of year........................  $    23,556   $    32,636   $    56,401
  Distributable income.................................    1,401,106     3,586,711     2,952,611
  Distributions to unitholders.........................   (1,401,106)   (3,586,711)   (2,952,611)
  Amortization of net overriding royalty interest......      (12,429)       (9,080)      (23,765)
                                                         -----------   -----------   -----------
Trust corpus, end of year..............................  $    11,127   $    23,556   $    32,636
                                                         ===========   ===========   ===========
</Table>

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

                                       25
<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 JPMorgan Chase Bank, as trustee (the
"Trustee"). JPMorgan Chase Bank was formerly known as The Chase Manhattan Bank
and is the successor by mergers to the original name of the Trustee, Texas
Commerce Bank National Association.

    The 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 $116,000,
    $137,000 and $132,000 for the years 2001, 2000 and 1999, 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.

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

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

    The December 31, 2001 reserve report prepared for the Partnership (See
Note 7) indicates that Royalty income expected to be received by the Trust in
2002 and thereafter could be at or near the Termination Threshold. The reserve
report estimates that future Royalty income to the Trust is approximately
$1.6 million while the Termination Threshold for 2001 was approximately
$1.3 million. Future Royalty income in the reserve report was calculated using
oil and natural gas spot prices in effect at December 31, 2001 of $19.76 per
barrel and $2.73 per Mcf, respectively. Based on the current estimates of
Royalty income and current market conditions, the Trustee expects that Royalty
income received by the Trust will be below the Termination Threshold in 2002. In
addition, depending on the future price of oil and natural gas, the timing of
production, market conditions, success of future drilling activity, if any, and
other matters the Royalty income received by the Trust after 2002 may also 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.

                                       27
<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, 2001, 2000 and 1999 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

                                       28
<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 expenses of the
Trust, which are expected to approximate $500,000 annually. The general and
administrative 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.

                                       29
<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, 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
    Revisions of previous estimates.........................    (12,550)    (111,423)
    Extensions, discoveries and other additions.............         --           --
    Production..............................................    (11,237)    (297,780)
                                                               --------    ---------
  December 31, 2001.........................................     13,174      492,205
                                                               ========    =========
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
                                                               ========    =========
  December 31, 2001.........................................     13,174      492,205
                                                               ========    =========
</Table>

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

(See Notes on following page.)

                                       30
<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 CONDENSATE AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM
                                  (UNAUDITED)

<Table>
<Caption>
                                                                 DECEMBER 31,
                                                              -------------------
                                                                2001       2000
                                                              --------   --------
                                                                (IN THOUSANDS)
<S>                                                           <C>        <C>
Ninety percent of future gross proceeds.....................  $ 3,031    $10,777
Less ninety percent of--
  Future operating costs....................................   (1,421)      (619)
  Future capital costs, net of amounts previously accrued...      (23)       (15)
                                                              -------    -------
Future royalty income.......................................    1,587     10,143
Discount at 10% per annum...................................     (337)    (1,367)
                                                              -------    -------
Standardized measure of future royalty income from proved
  oil and gas reserves......................................  $ 1,250    $ 8,776
                                                              =======    =======
</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,
                                                              ------------------------------
                                                                2001       2000       1999
                                                              --------   --------   --------
                                                                      (IN THOUSANDS)
<S>                                                           <C>        <C>        <C>
Standardized measure at beginning of year...................  $ 8,776    $ 4,247    $ 3,977
                                                              -------    -------    -------
  Revisions of previous estimates...........................     (582)    (3,218)    (4,629)
  Net changes in prices and production costs................   (6,049)    10,444      4,893
  Extensions, discoveries and other additions...............       --         --         --
  Royalty income............................................   (1,773)    (3,122)      (392)
  Accretion of discount.....................................      878        425        398
                                                              -------    -------    -------
  Net changes in standardized measure.......................   (7,526)     4,529        270
                                                              -------    -------    -------
Standardized measure at end of year.........................  $ 1,250    $ 8,776    $ 4,247
                                                              =======    =======    =======
</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,
  2001 includes, in thousands, $8,324 of future abandonment costs net of $8,324
  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.

                                       31
<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>
2001:
Royalty income................................  $  727,678   $  500,712     $346,443     $  197,762
Distributable income..........................  $  608,102   $  409,607     $241,454     $  141,943
Distributable income per unit.................  $   0.0084   $   0.0057     $ 0.0034     $   0.0020

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
</Table>

                                       32
<Page>
                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO JPMORGAN CHASE 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, 2001 and 2000, and the
related statements of distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 2001. 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.

    These financial statements were prepared on the basis of accounting
described in Note 3, 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, 2001 and 2000, and its distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 2001, on the basis of accounting described in Note 3.

                                               ARTHUR ANDERSEN LLP

Houston, Texas
March 25, 2002

                                       33
<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..........................       25
Statements of Assets, Liabilities and Trust Corpus..........       25
Statements of Changes in Trust Corpus.......................       25
Notes to Financial Statements...............................       26
Report of Independent Public Accountants....................       33
</Table>

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

    (A)(2)SCHEDULES

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

                                       34
<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)

99.1  Temporary Note 3T to Article 3 of Regulation S-X............
</Table>

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

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

(B) REPORTS ON FORM 8-K

    No reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust during the fourth quarter of 2001.

                                       35
<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   JPMORGAN CHASE BANK, TRUSTEE

                                                       By                /s/ MIKE ULRICH
                                                            -----------------------------------------
                                                                           Mike Ulrich
                                                              SENIOR VICE PRESIDENT & TRUST OFFICER
</Table>

March 25, 2002

    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.

                                       36
<Page>
EXHIBIT INDEX

<Table>
<Caption>
                                                                       SEC FILE OR
EXHIBIT                                                                REGISTRATION      EXHIBIT
NUMBER                                                                    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)

99.1     Temporary Note 3T to Article 3 of Regulation S-X............
</Table>

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

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