<Page>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-Q
<Table>
/X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD
ENDED SEPTEMBER 30, 2001
/ / 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>
TEXAS 76-6004065
(STATE OF INCORPORATION (I.R.S. EMPLOYER
OR ORGANIZATION) IDENTIFICATION NO.)
JPMORGAN CHASE BANK
INSTITUTIONAL TRUST SERVICES
700 LAVACA
AUSTIN, TEXAS 78701
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
</Table>
1-512-479-2562
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
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 the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
As of November 13, 2001--71,980,216 Units of Beneficial Interest in Mesa
Offshore Trust.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<Page>
PART I--FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------------- --------------------------------
2001 2000 2001 2000
------------- ------------- ------------- -------------
Royalty income................ $ 346,443 $ 461,949 $ 1,574,833 $ 2,399,353
Interest income............... 23,244 56,502 82,486 120,369
General and administrative
expense..................... (128,233) (101,937) (398,157) (373,428)
------------- ------------- ------------- -------------
Distributable income........ $ 241,454 $ 416,514 $ 1,259,162 $ 2,146,294
============= ============= ============= =============
Distributable income per
unit...................... $ 0.0034 $ 0.0058 $ 0.0175 $ 0.0298
============= ============= ============= =============
</Table>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<Table>
<Caption>
SEPTEMBER 30, DECEMBER 31,
2001 2000
------------- -------------
(UNAUDITED)
ASSETS
Cash and short-term investments............................. $ 2,218,210 $ 3,427,324
Interest receivable......................................... 23,244 13,092
Net overriding royalty interest in oil and gas properties... 380,905,000 380,905,000
Accumulated amortization.................................... (380,885,101) (380,881,444)
------------- -------------
Total assets........................................ $ 2,261,353 $ 3,463,972
============= =============
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses.................................. $ 2,000,000 $ 2,000,000
Distributions payable....................................... 241,454 1,440,416
Trust corpus (71,980,216 units of beneficial interest
authorized and outstanding)............................... 19,899 23,556
------------- -------------
Total liabilities and trust corpus...................... $ 2,261,353 $ 3,463,972
============= =============
</Table>
(The accompanying notes are an integral part of these financial statements.)
1
<Page>
MESA OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------------
2001 2000 2001 2000
--------- --------- ------------- -----------
Trust corpus, beginning of period.... $ 20,703 $ 19,385 $ 23,556 $ 32,636
Distributable income............... 241,454 416,514 1,259,162 2,146,294
Distributions to unitholders....... (241,454) (416,514) (1,259,162) (2,146,294)
Amortization of net overriding
royalty interest................. (804) (3,159) (3,657) (16,410)
--------- --------- ------------- -----------
Trust corpus, end of period.......... $ 19,899 $ 16,226 $ 19,899 $ 16,226
========= ========= ============= ===========
</Table>
(The accompanying notes are an integral part of these financial statements.)
2
<Page>
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1--TRUST ORGANIZATION
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 the predecessor to MESA Inc., transferred to the Trust a 99.99%
interest in the Mesa Offshore Royalty Partnership (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. As used in this report, the term
PNR generally refers to the operator of the Royalty Properties, unless otherwise
indicated.
STATUS OF THE TRUST
The Trust Indenture provides that the Trust will terminate if the total
amount of cash per year received by the Trust falls below certain levels for
each of three successive years (the "Termination Threshold"). The December 31,
2000 reserve report prepared for the Partnership (see the Trust's 2000 Annual
Report on Form 10-K) indicates that Royalty income expected to be received by
the Trust in 2003 and thereafter could be at or near the Termination Threshold.
The reserve report estimates that future Royalty income to the Trust is
approximately $10.1 million while the Termination Threshold for 2000 was
approximately $1.3 million. Future Royalty income in the reserve report was
calculated using oil and natural gas prices in effect at December 31, 2000 of
$26.30 per barrel and $10.17 per Mcf, respectively. Since December 31, 2000,
natural gas prices have declined significantly; consequently, future Royalty
income would be significantly reduced if calculated using current prices. It is
therefore possible, based on current gas prices, (depending on the timing of
production, market conditions, success of future drilling activity, if any, and
other matters) that in 2002 and thereafter Royalty income received by the Trust
may be below the Termination Threshold. If Royalty income falls below the
Termination Threshold for three successive years, the Trust would terminate
pursuant to the terms discussed above. There are numerous uncertainties inherent
in estimating and projecting the quantity and value of proved reserves for the
Trust properties as many of the Trust properties are nearing the end of their
productive lives and are therefore subject to unforeseen changes in production
rates. As such, there can be no assurance that Royalty income received by the
Trust in 2002 or thereafter will be above the Termination Threshold.
3
<Page>
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
NOTE 2--BASIS OF PRESENTATION
The accompanying unaudited financial information has been prepared by
JPMorgan Chase Bank (the "Trustee"), JPMorgan Chase Bank formerly known as The
Chase Manhattan Bank formerly known as Chemical Bank successor by merger to The
Chase Manhattan Bank, National Association, in accordance with the instructions
to Form 10-Q. The Trustee believes such information includes all the disclosures
necessary to make the information presented not misleading. The information
furnished reflects all adjustments which are, in the opinion of the Trustee,
necessary for a fair presentation of the results for the interim periods
presented. The financial information should be read in conjunction with the
financial statements and notes thereto included in the Trust's 2000 Annual
Report on Form 10-K.
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;
(c) Trust general and administrative expenses, net of reimbursements,
are recorded in the month they accrue;
(d) Amortization of the net overriding royalty interest, 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 amount
does not affect distributable income; and
(e) Distributions payable are determined on a monthly basis and are
payable to unitholders of record as of the last business day of each month
or such other day as the Trustee determines is required to comply with legal
or stock exchange requirements. However, cash distributions are made
quarterly in January, April, July and October, and include interest earned
from the monthly record dates to the date of distribution.
This basis for reporting Royalty 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. Under these accounting principles, Royalty income
for a month would be based on net proceeds from production for such month
without regard to when calculated or received and interest income for a month
would be calculated only through the end of such month.
The instruments conveying the Royalty provide that the working interest
owner will calculate and pay the Partnership each month an amount equal to 90%
of the net proceeds for the preceding month. Generally, net proceeds means the
excess of the amounts received by the working interest owner from sales of oil
and gas from the Royalty Properties plus other cash receipts over operating and
capital costs incurred.
4
<Page>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q 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-Q, including without
limitation the statements under "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 has advised the Trust that it
believes that the expectations reflected in such forward-looking statements
contained herein 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-Q, including without limitation in conjunction
with the forward-looking statements included in this Form 10-Q and in the
Trust's Form 10-K. All subsequent written and oral forward-looking statements
attributable to the Trust or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.
FINANCIAL REVIEW
Distributable income of the Trust in the third quarter of 2001 was $241,454,
or $.0034 per unit, as compared to $416,514, or $.0058 per unit, in the third
quarter of 2000. There was no distribution of income for the month of July 2001,
as the Trust expenses incurred were greater than the Royalty Income received.
The per unit distributions for the third quarter of 2001 and 2000 were as
follows:
<Table>
<Caption>
2001 2000
-------- --------
July..................................................... -- $.0012
August................................................... .0026 .0006
September................................................ .0008 .0040
------ ------
$.0034 $.0058
====== ======
</Table>
Royalty income decreased to $346,443 in the third quarter of 2001 as
compared to $461,949 in the third quarter of 2000. The decrease in Royalty
income is primarily due to lower oil production at West Delta 61 and 62. The
decrease in oil production can be attributed to natural production decline.
Production volumes for natural gas increased to 120,922 Mcf in the third
quarter of 2001 from 117,025 Mcf in the third quarter of 2000. The increase is
primarily due to increased production at Matagorda Island 624, that resulted
from successful workovers during the quarter. The Matagorda Island 624 increase
was partially offset by decreased production at Brazos A-7 and A-39, which is
due to natural production decline. The average price received for natural gas
was $4.44 per Mcf in the third quarter of 2001 as compared to $3.46 per Mcf in
the third quarter of 2000.
Crude oil, condensate and natural gas liquids production decreased to 2,979
barrels in the third quarter of 2001 from 10,464 barrels in the third quarter of
2000 and from 5,281 barrels in the second quarter of 2001. The average price
received for crude oil, condensate and natural gas liquids was $26.50 per barrel
in the third quarter of 2001, compared to $29.29 per barrel in the third quarter
of 2000.
5
<Page>
For the nine months ended September 30, 2001, natural gas production volumes
decreased to 367,275 Mcf from 763,875 Mcf for the nine months ended
September 30, 2000. The average price received for natural gas was $5.38 per Mcf
for the nine months ended September 30, 2001 compared to $2.89 per Mcf for the
nine months ended September 30, 2000. Crude oil, condensate and natural gas
liquid volumes decreased to 14,722 barrels in the first nine months of 2001 as
compared to 44,852 barrels in the first nine months of 2000. The average price
received for crude oil, condensate and natural gas liquids was $26.22 per barrel
for the nine months ended September 30, 2001 compared to $25.42 per barrel for
the nine months ended September 30, 2000.
The amount of cash distributed by the Trust is dependent on, among other
things, the sales prices and quantities of natural gas, crude oil, condensate
and natural gas liquids produced from the Royalty Properties and the quantities
sold. Substantial uncertainties exist with regard to future natural 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.
OPERATIONAL REVIEW
PNR has advised the Trust that during the third quarter of 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 in the third quarter of 2001 were generally higher than
spot market prices in the third quarter of 2000.
The Brazos A-7 and A-39 blocks experienced a decrease in natural gas
production in the third quarter of 2001 as compared to the third quarter of 2000
primarily due to natural production decline as two wells ceased production. PNR
is planning to perform a workover during the fourth quarter 2001 at Brazos A-39
in an attempt to reestablish production. Also, PNR farmed out their interest and
the Trust's interest in one-fourth of the Brazos A-39 block to Shell Oil Company
in late 2000 in return for a 2% override (1.8% net to the Trust) in one-fourth
of the Brazos A-39 block farmed out and one-fourth of three surrounding blocks.
If the workover is unsuccessful and Shell does not commence drilling operations
on their prospect within approximately six months, PNR will be required to
commence drilling operations on its one remaining prospect on the block, or
relinquish the block and begin plugging and abandonment operations. PNR farmed
out a portion of the Brazos A-7 block to Newfield Exploration Co. and
participated in a 10% working interest in the completion of an exploratory gas
well drilled in the second quarter of 1997. The No. B-1 well commenced
production late in the fourth quarter of 1998 and is currently producing at a
rate of approximately 3.1 MMcf of natural gas per day.
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 well ceased production again in February 2000. PNR commenced
abandonment procedures during the second quarter of 2001. These procedures are
expected to be completed in April of 2002.
The West Delta 61 and 62 blocks experienced a decrease in oil production and
an increase in natural gas production in the third quarter of 2001, as compared
to the third quarter of 2000, due to higher production from successful workovers
that were performed in the third quarter of 2001. In portions of
6
<Page>
West Delta block 62, the Trust is receiving Royalty income pursuant to a farmout
agreement with Walter Oil and Gas Corporation. The interest in the farmout well
that is attributable to the Trust consists of a 7.5% net profits interest. The
well is currently producing at a rate of approximately 220 Mcf and 10 barrels of
condensate per day. In West Delta block 61, PNR farmed out portions of the block
to Stone Energy Corporation (formerly Basin Exploration), retaining a 12.5%
(11.25% net to the Trust) overriding royalty interest. The operator drilled
three exploratory wells, two of which were successful. The two successful wells
began producing during the second quarter of 1999 and are currently producing at
a combined rate of approximately 80 Mcf and 6 barrels of condensate per day.
Matagorda Island 624 production increased in the third quarter of 2001 as
compared to the third quarter of 2000, primarily due to a workover that was
performed in the second quarter of 2001. Currently gross production for the
block is approximately 1.6 MMcf per day and 20 barrels of condensate per day.
TERMINATION OF THE TRUST
The terms of the Mesa Offshore Trust Indenture provide, among other things,
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 ten times
one-third of the total amount payable to the Trustee as compensation for such
three-year period ("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 the Trust's 2000 Annual Report on
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 the Trust's 2000 Annual Report on
Form 10-K and is available upon request from the Trustee.
The December 31, 2000 reserve report prepared for the Partnership indicates
that Royalty income expected to be received by the Trust in 2003 and thereafter
could be below the Termination Threshold. The reserve report estimates that
future Royalty income to the Trust is approximately $10.1 million, while the
Termination Threshold for 2000 was approximately $1.3 million. Future Royalty
income in the reserve report was calculated using oil and natural gas prices in
effect at December 31, 2000 of $26.30 per barrel and $10.17 per Mcf,
respectively. Since December 31, 2000, natural gas prices have declined
significantly; consequently, future Royalty income would be significantly
reduced if calculated using current prices. It is therefore possible, based on
current natural gas prices, (depending on the timing of production, market
conditions, success of future drilling activity, if any, and other matters) that
in 2002 and thereafter Royalty income received by the Trust may be below the
Termination Threshold. If Royalty income falls below the Termination Threshold
for three successive years, the Trust would terminate pursuant to the terms
discussed above. There are numerous uncertainties inherent in estimating and
projecting the quantity and value of proved reserves for the Trust properties as
many of the Trust properties are nearing the end of their productive lives and
are therefore subject to unforeseen changes in production rates. As such, there
can be no assurance that Royalty income received by the Trust in 2002 or
thereafter will be above the Termination Threshold.
7
<Page>
The terms of the First Amended and Restated Articles of General Partnership
of the Partnership provide that the Partnership shall dissolve upon the
occurrence of any of the following: (a) December 31, 2030; (b) the election of
the Trustee to dissolve the Partnership; (c) the termination of the Trust; (d)
the bankruptcy of the Managing General Partner; or (e) 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. In the
event of a dissolution of the Partnership and a subsequent winding up and
termination thereof, the assets of the Partnership (i.e., the Royalty interest)
could either (i) be distributed in kind ratably to the Managing General Partner
and the Trustee or (ii) 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.
8
<Page>
The following tables provide a summary of the calculations of the net
proceeds attributable to the Partnership's Royalty interest (unaudited):
<Table>
<Caption>
SOUTH MARSH
BRAZOS A-7 ISLAND 155 WEST DELTA MATAGORDA
AND A-39 AND 156 61 AND 62 ISLAND 624 TOTAL
---------- ----------- ---------- ---------- ----------
THREE MONTHS ENDED SEPTEMBER 30, 2001:
Ninety percent of gross proceeds............. $ 188,490 $ (977) $ 198,720 $229,187 $ 615,420
Less ninety percent of--
Operating expenditures..................... (93,153) (26,102) (72,074) (74,310) (265,639)
Capital costs recovered.................... -- -- -- (3,303) (3,303)
Accrual for future abandonment costs and
interest on cost carryforward............ -- -- -- -- --
--------- --------- ---------- -------- ----------
Net proceeds (excess costs).................. $ 95,337 $ (27,079) $ 126,646 $151,574 $ 346,478
Trust share of net proceeds (99.99%)......... $ 346,443
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 13 -- 2,674 292 2,979
========= ========= ========== ======== ==========
Average sales price per Bbl................ $ 24.85 $ -- $ 26.30 $ 28.40 $ 26.50
========= ========= ========== ======== ==========
Natural gas (Mcf).......................... 42,786 -- 28,270 49,866 120,922
========= ========= ========== ======== ==========
Average sales price per Mcf................ $ 4.40 $ -- $ 4.56 $ 4.43 $ 4.44
========= ========= ========== ======== ==========
Producing wells.............................. 1 -- 3 1 5
<Caption>
SOUTH MARSH
BRAZOS A-7 ISLAND 155 WEST DELTA MATAGORDA
AND A-39 AND 156 61 AND 62 ISLAND 624 TOTAL
---------- ----------- ---------- ---------- ----------
THREE MONTHS ENDED SEPTEMBER 30, 2000:
Ninety percent of gross proceeds............. $ 331,870 $ 1,394 $ 330,346 $ 47,314 $ 710,924
Less ninety percent of--
Operating expenditures..................... (84,722) (22,121) (97,500) (14,586) (218,929)
Capital costs recovered.................... -- -- -- -- --
Accrual for future abandonment costs and
interest on cost carryforward............ (16,059) (62) (11,794) (2,085) (30,000)
--------- --------- ---------- -------- ----------
Net proceeds................................. $ 231,089 $ (20,789) $ 221,052 $ 30,643 $ 461,995
Trust share of net proceeds (99.99%)......... $ 461,949
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 359 48 9,742 315 10,464
========= ========= ========== ======== ==========
Average sales price per Bbl................ $ 27.09 $ 26.73 $ 29.49 $ 25.98 $ 29.29
========= ========= ========== ======== ==========
Natural gas (Mcf).......................... 94,099 82 12,236 10,608 117,025
========= ========= ========== ======== ==========
Average sales price per Mcf................ $ 3.42 $ 1.51 $ 3.52 $ 3.69 $ 3.46
========= ========= ========== ======== ==========
Producing wells............................ 3 -- 3 1 7
</Table>
- ------------------------------
- - The amounts shown are for Mesa Offshore Royalty Partnership.
- - The amounts for the three months ended September 30, 2001 and 2000 represent
actual production for the periods May 2001 through July 2001 and May 2000
through July 2000, respectively.
- - Capital costs recovered represents capital costs incurred during the current
or prior periods to the extent that such costs have been recovered by PNR from
current period Gross Proceeds.
- - Producing wells indicate the number of wells capable of production as of the
end of the period.
9
<Page>
<Table>
<Caption>
SOUTH MARSH
BRAZOS A-7 ISLAND 155 WEST DELTA MATAGORDA
AND A-39 AND 156 61 AND 62 ISLAND 624 TOTAL
---------- ----------- ---------- ---------- ----------
NINE MONTHS ENDED SEPTEMBER 30, 2001:
Ninety percent of gross proceeds............... $1,178,708 $ (727) $ 906,154 $ 279,101 $2,363,236
Less ninety percent of--
Operating expenditures..................... (250,759) (114,198) (198,207) (146,127) (709,291)
Capital costs recovered.................... (48,703) (2,124) -- (18,127) (68,954)
Accrual for future abandonment costs....... (6,106) -- (3,822) (72) (10,000)
---------- ---------- ---------- --------- ----------
Net proceeds (excess costs).................. $ 873,140 $ (117,049) $ 704,125 $ 114,775 $1,574,991
Trust share of net proceeds (99.99%)......... $1,574,833
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 234 -- 13,780 708 14,722
========== ========== ========== ========= ==========
Average sales price per Bbl................ $ 27.09 $ -- $ 12.93 $ 25.04 $ 26.22
========== ========== ========== ========= ==========
Natural gas (Mcf).......................... 215,938 89 95,063 56,185 367,275
========== ========== ========== ========= ==========
Average sales price per Mcf................ $ 5.43 $ -- $ 5.72 $ 4.65 $ 5.38
========== ========== ========== ========= ==========
Producing wells.............................. 1 -- 3 1 5
<Caption>
SOUTH MARSH
BRAZOS A-7 ISLAND 155 WEST DELTA MATAGORDA
AND A-39 AND 156 61 AND 62 ISLAND 624 TOTAL
---------- ----------- ---------- ---------- ----------
NINE MONTHS ENDED SEPTEMBER 30, 2000:
Ninety percent of gross proceeds............. $1,044,852 $ 93,095 $2,023,387 $ 185,569 $3,346,903
Less ninety percent of--
Operating expenditures..................... (263,937) (205,137) (232,737) (90,240) (792,051)
Capital costs recovered.................... -- (95,259) -- -- (95,259)
Accrual for future abandonment costs....... (30,481) (11,557) (13,410) (4,552) (60,000)
---------- ---------- ---------- --------- ----------
Net proceeds................................. $ 750,434 $ (218,858) $1,777,240 $ 90,777 $2,399,593
Trust share of net proceeds (99.99%)......... $2,399,353
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 975 593 42,282 1,002 44,852
========== ========== ========== ========= ==========
Average sales price per Bbl................ $ 26.10 $ 26.48 $ 25.35 $ 27.11 $ 25.42
========== ========== ========== ========= ==========
Natural gas (Mcf).......................... 360,707 33,457 315,790 53,921 763,875
========== ========== ========== ========= ==========
Average sales price per Mcf................ $ 2.83 $ 2.31 $ 3.01 $ 2.94 $ 2.89
========== ========== ========== ========= ==========
Producing wells.............................. 3 -- 3 1 7
</Table>
- ------------------------------
- The amounts shown are for Mesa Offshore Royalty Partnership.
- The amounts for the nine months ended September 30, 2001 and 2000
represent actual production for the periods November 2000 through July
2001, and November 1999 through July 2000, respectively.
- Capital costs recovered represents capital costs incurred during the
current or prior periods to the extent that such costs have been recovered
by PNR from current period Gross Proceeds.
- Producing wells indicate the number of wells capable of production as of
the end of the period.
10
<Page>
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Trust does not utilize market risk sensitive instruments. However, see
the discussion of marketing by PNR above.
PART II
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(A) EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference. JPMorgan Chase Bank
formerly known as The Chase Manhattan Bank, formerly known as Chemical Bank,
successor by merger to The Chase Manhattan Bank, National Association, which was
the successor name of Texas Commerce Bank, National Association, in accordance
with the instruction to form 10-Q.
<Table>
<Caption>
SEC FILE OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ --------
4(a) *Mesa Offshore Trust Indenture between Mesa Petroleum Co.
and Texas Commerce Bank National Association, as Trustee,
dated December 15, 1982................................... 2-79673 10(gg)
4(b) *Overriding Royalty Conveyance between Mesa Petroleum Co.
and Mesa Offshore Royalty Partnership, dated December 15,
1982...................................................... 2-79673 10(hh)
4(c) *Partnership Agreement between Mesa Offshore Management Co.
and Texas Commerce Bank National Association, as Trustee,
dated December 15, 1982................................... 2-79673 10(ii)
4(d) *Amendment to Partnership Agreement between Mesa Offshore
Management Co., Texas Commerce Bank National Association,
as Trustee, and Mesa Operating Limited Partnership, dated
December 27, 1985 (Exhibit 4(d) to Form 10-K for year
ended December 31, 1992 of Mesa Offshore Trust)........... 1-8432 4(d)
4(e) *Amendment to Partnership Agreement between Texas Commerce
Bank National Association, as Trustee and Mesa Operating
dated as of January 5, 1994 (Exhibit 4(e) to Form 10-K for
year ended December 31, 1993 of Mesa Offshore Trust)...... 1-8432 4(e)
</Table>
(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 third quarter of 2001.
11
<Page>
SIGNATURES
Pursuant to the requirements 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>
MESA OFFSHORE TRUST
By: /S/ JPMORGAN CHASE BANK, TRUSTEE
By: /s/ MIKE ULRICH
------------------------------------------------
MIKE ULRICH
VICE PRESIDENT & TRUST OFFICER
</Table>
Date: November 13, 2001
The Registrant, Mesa Offshore Trust, has no principal executive officer,
principal financial officer, board of directors or persons performing similar
functions. Accordingly, no additional signatures are available and none have
been provided.
12