<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 ENDED JUNE 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.)
THE CHASE MANHATTAN BANK
INSTITUTIONAL TRUST DIVISION
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 August 10, 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------------- --------------------------------
2001 2000 2001 2000
------------- ------------- ------------- -------------
Royalty income................ $ 500,712 $ 622,981 $ 1,228,390 $ 1,937,404
Interest income............... 27,430 30,551 59,242 63,867
General and administrative
expense..................... (118,535) (194,447) (269,924) (271,491)
------------- ------------- ------------- -------------
Distributable income........ $ 409,607 $ 459,085 $ 1,017,708 $ 1,729,780
============= ============= ============= =============
Distributable income per
unit...................... $ .0057 $ .0064 $ .0141 $ .0240
============= ============= ============= =============
</Table>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2001 2000
------------- -------------
(UNAUDITED)
ASSETS
Cash and short-term investments............................. $ 2,382,177 $ 3,427,324
Interest receivable......................................... 27,430 13,092
Net overriding royalty interest in oil and gas properties... 380,905,000 380,905,000
Accumulated amortization.................................... (380,884,297) (380,881,444)
------------- -------------
Total assets........................................ $ 2,430,310 $ 3,463,972
============= =============
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses.................................. $ 2,000,000 $ 2,000,000
Distributions payable....................................... 409,607 1,440,416
Trust corpus (71,980,216 units of beneficial interest
authorized and outstanding)............................... 20,703 23,556
------------- -------------
Total liabilities and trust corpus...................... $ 2,430,310 $ 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------------
2001 2000 2001 2000
--------- --------- ------------- -----------
Trust corpus, beginning of period.... $ 21,979 $ 23,646 $ 23,556 $ 32,636
Distributable income............... 409,607 459,085 1,017,708 1,729,780
Distributions to unitholders....... (409,607) (459,085) (1,017,708) (1,729,780)
Amortization of net overriding
royalty interest................. (1,276) (4,261) (2,853) (13,251)
--------- --------- ------------- -----------
Trust corpus, end of period.......... $ 20,703 $ 19,385 $ 20,703 $ 19,385
========= ========= ============= ===========
</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 The
Chase Manhattan Bank (the "Trustee"), the successor by merger to the Chase Bank
of Texas, National Association, in accordance with the instructions to
Form 10-Q, and 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 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 second quarter of 2001 was
$409,607, or $.0057 per unit, as compared to $459,085, or $.0064 per unit, in
the second quarter of 2000. The per unit distributions for the second quarter of
2001 and 2000 were as follows:
<Table>
<Caption>
2001 2000
-------- --------
April.................................................... .0020 $.0036
May...................................................... .0031 .0019
June..................................................... .0006 .0009
------ ------
$.0057 $.0064
====== ======
</Table>
Royalty income decreased to $500,712 in the second quarter of 2001 as
compared to $622,981 in the second quarter of 2000. The decrease in Royalty
income is primarily due to lower production volumes from Brazos A-7 and A-39 and
West Delta 61 and 62, partially offset by higher oil and gas prices when
compared to the same period in 2000. The decreased production volumes can be
attributed to natural decline as one well ceased production at Brazos A-7 and
lower production from West Delta 61 and 62 due to natural production decline.
Production volumes for natural gas decreased to 92,876 Mcf in the second
quarter of 2001 from 218,889 Mcf in the second quarter of 2000. The average
price received for natural gas was $6.97 per Mcf in the second quarter of 2001
as compared to $2.63 per Mcf in the second quarter of 2000.
Crude oil, condensate and natural gas liquids production decreased to 5,281
barrels in the second quarter of 2001 from 11,709 barrels in the second quarter
of 2000. The average price received for crude oil, condensate and natural gas
liquids was $23.10 per barrel in the second quarter of 2001, compared to $27.33
per barrel in the second quarter of 2000.
For the six months ended June 30, 2001, natural gas production volumes
decreased to 246,353 Mcf from 646,852 Mcf for the six months ended June 30,
2000. The average price received for natural gas was
5
<Page>
$5.85 per Mcf for the six months ended June 30, 2001 compared to $2.79 per Mcf
for the six months ended June 30, 2000. Crude oil, condensate and natural gas
liquid volumes decreased to 11,743 barrels in the first six months of 2001 as
compared to 34,389 barrels in the first six months of 2000. The average price
received for crude oil, condensate and natural gas liquids was $26.15 per barrel
for the six months ended June 30, 2001 compared to $24.24 per barrel for the six
months ended June 30, 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.
OPERATIONAL REVIEW
PNR has advised the Trust that during the second 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 second quarter of 2001 were generally higher than
spot market prices in the second quarter of 2000.
The Brazos A-7 and A-39 blocks experienced a decrease in natural gas
production in the second quarter of 2001 as compared to the second quarter of
2000 primarily due to natural production decline as one well ceased production.
PNR farmed out a portion of the Brazos A-7 block to Newfield Exploration Co. and
participated at 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 4.5 MMcf and 6 barrels of condensate per day. PNR farmed
out their interest and the Trust's interest in one-fourth of the Brazos A-39
block to Shell Oil Company in late 2000 in return for a 2% override (1.8% net to
the Trust) in one-fourth of the Brazos A-39 block farmed out and one-fourth of
three surrounding blocks.
The South Marsh Island 155 and 156 blocks ceased production in the first
quarter of 2000. Four workovers were performed in 1999 to attempt to restore
production. While two were successful in restoring production for a short
period, the well ceased production again in February 2000. PNR commenced
abandonment procedures during the second quarter of 2001.
The West Delta 61 and 62 blocks experienced a decrease in oil and natural
gas production in the second quarter of 2001 as compared to the second quarter
of 2000 due to higher production in early 2000 from farmout agreements in late
1999. In portions of 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 wells that is attributable to the Trust consists of a
7.5% net profits interest. The wells are currently producing at a rate of 3.9
MMcf and 175 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 were producing at a combined rate of approximately .5 MMcf and 60
barrels of condensate per day as of August 2001.
6
<Page>
Matagorda Island 624 production increased in the second quarter of 2001 as
compared to the second quarter of 2000, primarily due to a workover that was
performed in the second quarter of 2001. Gross production for the block is
currently 3.3 MMcf per day and 41 barrels of condensate per day as of
August 2001 compared to .8 MMcf per day and 6 barrels of condensate per day as
of August 2001.
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.
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
7
<Page>
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.
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 JUNE 30, 2001:
Ninety percent of gross proceeds............. $ 402,285 $ -- $ 325,934 $ 41,137 $ 769,356
Less ninety percent of--
Operating expenditures..................... (77,530) (43,131) (79,335) (50,122) (250,118)
Capital costs recovered.................... (1,528) (2,124) -- (14,824) (18,476)
Accrual for future abandonment costs and
interest on cost carryforward............ -- -- -- -- --
--------- --------- ---------- -------- ----------
Net proceeds (excess costs).................. $ 323,227 $ (45,255) $ 246,599 $(23,809) $ 500,762
========= ========= ========== ======== ==========
Trust share of net proceeds (99.99%)......... $ 500,712
==========
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 78 -- 4,949 254 5,281
========= ========= ========== ======== ==========
Average sales price per Bbl................ $ 26.60 $ -- $ 22.93 $ 25.39 $ 23.10
========= ========= ========== ======== ==========
Natural gas (Mcf).......................... 56,643 -- 30,316 5,917 92,876
========= ========= ========== ======== ==========
Average sales price per Mcf................ $ 7.07 $ -- $ 7.01 $ 5.85 $ 6.97
========= ========= ========== ======== ==========
Producing wells.............................. 2 -- 3 1 6
<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 JUNE 30, 2000:
Ninety percent of gross proceeds............. $ 361,865 $ 43,102 $ 419,320 $ 72,242 $ 896,529
Less ninety percent of--
Operating expenditures..................... (78,438) (44,707) (61,537) (25,477) (210,159)
Capital costs recovered.................... -- (33,326) -- -- (33,326)
Accrual for future abandonment costs and
interest on cost carryforward............ (14,422) (11,495) (1,616) (2,467) (30,000)
--------- --------- ---------- -------- ----------
Net proceeds................................. $ 269,005 $ (46,426) $ 356,167 $ 44,298 $ 623,044
========= ========= ========== ======== ==========
Trust share of net proceeds (99.99%)......... $ 622,981
==========
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 381 523 10,519 286 11,709
========= ========= ========== ======== ==========
Average sales price per Bbl................ $ 26.61 $ 26.73 $ 27.21 $ 33.90 $ 27.33
========= ========= ========== ======== ==========
Natural gas (Mcf).......................... 136,711 12,437 47,676 22,065 218,889
========= ========= ========== ======== ==========
Average sales price per Mcf................ $ 2.57 $ 2.34 $ 2.79 $ 2.84 $ 2.63
========= ========= ========== ======== ==========
Producing wells............................ 3 -- 3 1 7
</Table>
- ------------------------------
- - The amounts shown are for Mesa Offshore Royalty Partnership.
- - The amounts for the three months ended June 30, 2001 and 2000 represent actual
production for the periods February 2001 through April 2001 and February 2000
through April 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.
8
<Page>
<Table>
<Caption>
SOUTH MARSH
BRAZOS A-7 ISLAND 155 WEST DELTA MATAGORDA
AND A-39 AND 156 61 AND 62 ISLAND 624 TOTAL
---------- ----------- ---------- ---------- ----------
SIX MONTHS ENDED JUNE 30, 2001:
Ninety percent of gross proceeds............... $ 990,218 $ 250 $ 707,434 $ 49,914 $1,747,816
Less ninety percent of--
Operating expenditures..................... (157,606) (88,096) (126,133) (71,817) (443,652)
Capital costs recovered.................... (48,703) (2,124) -- (14,824) (65,651)
Accrual for future abandonment costs....... (6,106) -- (3,822) (72) (10,000)
--------- ---------- ---------- -------- ----------
Net proceeds (excess costs).................. $ 777,803 $ (89,970) $ 577,479 $(36,799) $1,228,513
========= ========== ========== ======== ==========
Trust share of net proceeds (99.99%)......... $1,228,390
==========
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 221 -- 11,106 416 11,743
========= ========== ========== ======== ==========
Average sales price per Bbl................ $ 27.26 $ -- $ 26.26 $ 22.69 $ 26.15
========= ========== ========== ======== ==========
Natural gas (Mcf).......................... 173,152 25 66,857 6,319 246,353
========= ========== ========== ======== ==========
Average sales price per Mcf................ $ 5.68 $ 10.00 $ 6.22 $ 6.40 $ 5.85
========= ========== ========== ======== ==========
Producing wells.............................. 2 -- 3 1 6
<Caption>
SOUTH MARSH
BRAZOS A-7 ISLAND 155 WEST DELTA MATAGORDA
AND A-39 AND 156 61 AND 62 ISLAND 624 TOTAL
---------- ----------- ---------- ---------- ----------
SIX MONTHS ENDED JUNE 30, 2000:
Ninety percent of gross proceeds............. $ 712,982 $ 91,701 $1,693,041 $138,255 $2,635,979
Release of MMS royalty reserve...............
Less ninety percent of--
Operating expenditures..................... (179,215) (183,016) (135,237) (75,654) (573,122)
Capital costs recovered.................... -- (95,259) -- -- (95,259)
Accrual for future abandonment costs....... (14,422) (11,495) (1,616) (2,467) (30,000)
--------- ---------- ---------- -------- ----------
Net proceeds................................. $ 519,345 $ (198,069) $1,556,188 $ 60,134 $1,937,598
========= ========== ========== ======== ==========
Trust share of net proceeds (99.99%)......... $1,937,404
==========
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 615 546 32,541 687 34,389
========= ========== ========== ======== ==========
Average sales price per Bbl................ $ 25.52 $ 26.46 $ 24.11 $ 27.62 $ 24.24
========= ========== ========== ======== ==========
Natural gas (Mcf).......................... 266,609 33,375 303,555 43,313 646,852
========= ========== ========== ======== ==========
Average sales price per Mcf................ $ 2.62 $ 2.31 $ 2.99 $ 2.75 $ 2.79
========= ========== ========== ======== ==========
Producing wells.............................. 3 -- 3 1 7
</Table>
- ------------------------------
- The amounts shown are for Mesa Offshore Royalty Partnership.
- The amounts for the six months ended June 30, 2001 and 2000 represent
actual production for the periods November 2000 through April 2001, and
November 1999 through April 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>
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. The Chase Manhattan
Bank is successor by merger to Chase Bank of Texas, National Association. Chase
Bank of Texas, National Association was the successor name of Texas Commerce
Bank National Association.)
<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 second quarter of 2001.
10
<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/ THE CHASE MANHATTAN BANK,
By: /s/ MIKE ULRICH
------------------------------------------------
MIKE ULRICH
SENIOR VICE PRESIDENT & TRUST OFFICER
</Table>
Date: August 10, 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.
11