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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
/X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD
ENDED ENDED MARCH 31, 2002
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD
FROM TO
Commission file number 1-8432
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MESA OFFSHORE TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-6004065
(State of Incorporation (I.R.S. Employer
or Organization) Identification No.)
JPMORGAN CHASE BANK, TRUSTEE
INSTITUTIONAL TRUST SERVICES
700 LAVACA
AUSTIN, TEXAS 78701
(Address of Principal Executive Offices) (Zip Code)
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 April 24, 2002--71,980,216 Units of Beneficial Interest in Mesa
Offshore Trust.
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PART I--FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
--------------------------------
2002 2001
------------- -------------
Royalty income.............................................. $ -- $ 727,678
Interest income............................................. 7,313 31,812
General and administrative expense.......................... (7,313) (151,388)
------------- -------------
Distributable income...................................... $ -- $ 608,102
============= =============
Distributable income per unit............................. $ -- $ .0084
============= =============
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
MARCH 31, DECEMBER 31,
2002 2001
------------- -------------
(UNAUDITED)
ASSETS
Cash and short-term investments............................. $ 1,839,629 $ 2,136,891
Interest receivable......................................... 7,313 5,052
Net overriding royalty interest in oil and gas properties... 380,905,000 380,905,000
Accumulated amortization.................................... (380,893,873) (380,893,873)
------------- -------------
Total assets.............................................. $ 1,858,069 $ 2,153,070
============= =============
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses.................................. $ 1,846,942 $ 2,000,000
Distributions payable....................................... -- 141,943
Trust corpus (71,980,216 units of beneficial interest
authorized and outstanding)............................... 11,127 11,127
------------- -------------
Total liabilities and trust corpus........................ $ 1,858,069 $ 2,153,070
============= =============
(The accompanying notes are an integral part of these financial statements.)
1
MESA OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
---------------------
2002 2001
--------- ---------
Trust corpus, beginning of period........................... $ 11,127 $ 23,556
Distributable income...................................... -- 608,102
Distributions to unitholders.............................. -- (608,102)
Amortization of net overriding royalty interest........... -- (1,577)
--------- ---------
Trust corpus, end of period................................. $ 11,127 $ 21,979
========= =========
(The accompanying notes are an integral part of these financial statements.)
2
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 hereinafter 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,
2001 reserve report prepared for the Partnership (see the Trust's 2001 Annual
Report on Form 10-K) 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 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.
3
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 ("Trustee") in accordance with the instructions to
Form 10-Q. 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 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 2001 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 because, under such accounting principles, royalty
income for a month would be based on net proceeds from production for such month
without regard to when calculated or received and interest income for a month
would be calculated only through the end of such month.
The instruments conveying the Royalty provide that the working interest
owner will calculate and pay the Partnership each month an amount equal to 90%
of the net proceeds for the preceding month. Generally, net proceeds means the
excess of the amounts received by the working interest owner from sales of oil
and gas from the Royalty Properties plus other cash receipts over operating and
capital costs incurred. For the three months ended March 31, 2002, operating and
capital costs incurred exceeded proceeds from oil and gas sales; accordingly, no
Royalty income was reported.
4
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, including under the section "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.
FINANCIAL REVIEW
During the first quarter of 2002, the Trust had no distributable income,
compared to $608,102, representing $.0084 per unit in the first quarter of 2001.
The decrease in distributable income in 2002 was primarily due to lower
production at Brazos A-7 and A-39 and West Delta 61 and 62 as described in the
"Operational Review" below. The per unit amounts of distributable income for the
first quarter of 2002 and 2001 were earned by month as follows:
2002 2001
-------- --------
January.................................................. $ -- $.0027
February................................................. -- .0029
March.................................................... -- .0028
------ ------
$ -- $.0084
There was no royalty income in the first quarter of 2002 as compared to
$727,678 for the first quarter of 2001. The decrease in royalty income is
primarily due to substantially lower production volumes on Brazos A-7 and A-39
and West Delta 61 and 62, partially offset by increased production at Matagorda
Island 624 and decreased prices for natural gas, crude oil and condensate as
compared to the same period in 2001.
There is a deficit balance due PNR as of March 31, 2002 of $108,479 that
will be deducted from any future gross proceeds on the Royalty properties, which
deduction will reduce future Royalty income.
Production volumes for natural gas decreased to 137,966 Mcf in the first
quarter of 2002 from 153,477 Mcf in the first quarter of 2001. The average price
received for natural gas was $2.20 per Mcf in the first quarter of 2002 as
compared to $5.17 per Mcf in the first quarter of 2001.
Crude oil, condensate and natural gas liquids production decreased to 3,353
barrels in the first quarter of 2001 from 6,462 barrels in the first quarter of
2001. The average price received for crude oil, condensate
5
and natural gas liquids was $21.80 per barrel in the first quarter of 2002 as
compared to $28.63 per barrel in the first quarter of 2001.
OPERATIONAL REVIEW
PNR has advised the Trust that during the first quarter of 2002 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 first quarter of 2002 were generally lower than
spot market prices in the first quarter of 2001.
The amount of cash distributed by the Trust is dependent on, among other
things, the sales prices and quantities of gas, crude oil and condensate
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 the
first quarter of 2002 as compared to the first quarter of 2001 primarily 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. In addition, there is one well producing on Brazos
A-39. 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 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. PNR commenced abandonment procedures during the second quarter
of 2001. These procedures are expected to be completed in the summer of 2002.
The West Delta 61 and 62 blocks experienced a decrease in production in the
first quarter of 2002 as compared to the first quarter of 2001 due to 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 Oil and Gas
Corporation ("Walter"). However, the well ceased production during the first
quarter of 2002 and Walter has informed PNR 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 their two wells shut-in for a
conversion from a manned platform to an unmanned platform. It is anticipated
that these wells will be back on production around July 2002.
Matagorda Island 624 production increased in the first quarter of 2002 as
compared to the first quarter of 2001, primarily due to a workover that was
performed in the second quarter of 2001. During the first quarter of 2002, the
well ceased production and another workover has been started to re-establish
production. This is the last behind-pipe reserves that PNR has identified on
this block, and there are no prospects on this block. Therefore, once this
reservoir is depleted in this last producing well, PNR currently expects that
plugging and abandonment procedures will be the next operation on this block.
6
The following tables provide a summary of the calculations of the net
proceeds attributable to the Partnership's royalty interest (unaudited):
SOUTH MARSH
BRAZOS A-7 ISLAND 155 WEST DELTA MATAGORDA
AND A-39 AND 156 61 AND 62 ISLAND 624 TOTAL
---------- ----------- ---------- ---------- ----------
THREE MONTHS ENDED MARCH 31, 2002:
Ninety percent of gross proceeds............. $ 114,129 $ -- $ 112,102 $150,084 $ 376,315
Less ninety percent of--
Operating expenditures..................... (231,443) (32,062) (71,934) (40,769) (376,208)
Capital costs recovered.................... -- -- -- (107) (107)
Accrual for future abandonment costs....... -- -- -- -- --
--------- --------- ---------- -------- ----------
Net proceeds (excess costs).................. $(117,314) $ (32,062) $ 40,168 $109,208 $ --
========= ========= ========== ======== ==========
Trust share of net proceeds (99.99%)......... $ --
==========
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 201 -- 2,328 824 3,353
========= ========= ========== ======== ==========
Average sales price per Bbl................ $ 18.68 $ -- $ 22.59 $ 20.31 $ 21.80
========= ========= ========== ======== ==========
Natural gas (Mcf).......................... 55,923 -- 21,165 60,878 137,966
========= ========= ========== ======== ==========
Average sales price per Mcf................ $ 1.97 $ -- $ 2.81 $ 2.19 $ 2.20
========= ========= ========== ======== ==========
Producing wells.............................. 2 -- -- -- 2
========= ========= ========== ======== ==========
THREE MONTHS ENDED MARCH 31, 2001:
Ninety percent of gross proceeds............. $ 587,932 $ 250 $ 381,500 $ 8,777 $ 978,459
Less ninety percent of--
Operating expenditures..................... (80,076) (44,965) (46,798) (21,695) (193,534)
Capital costs recovered.................... (47,174) -- -- -- (47,174)
Accrual for future abandonment costs....... (6,106) -- (3,822) (72) (10,000)
--------- --------- ---------- -------- ----------
Net proceeds (excess costs).................. $ 454,576 $ (44,715) $ 330,880 $(12,990) $ 727,751
========= ========= ========== ======== ==========
Trust share of net proceeds (99.99%)......... $ 727,678
==========
Production Volumes and Average Prices:
Crude oil, condensate and natural gas
liquids (Bbls)........................... 143 -- 6,157 162 6,462
========= ========= ========== ======== ==========
Average sales price per Bbl................ $ 27.56 $ -- $ 28.93 $ 18.46 $ 28.63
========= ========= ========== ======== ==========
Natural gas (Mcf).......................... 116,509 25 36,541 402 153,477
========= ========= ========== ======== ==========
Average sales price per Mcf................ $ 5.01 $ 10.14 $ 5.57 $ 14.40 $ 5.17
========= ========= ========== ======== ==========
Producing wells.............................. 3 -- 2 1 6
========= ========= ========== ======== ==========
------------------------------
- The amounts shown are for Mesa Offshore Royalty Partnership.
- The amounts for the three months ended March 31, 2002 and 2001 represent
actual production for the periods November 2001 through January 2002 and
November 2000 through January 2001, 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.
- At March 31, 2002, the cost carryforward was $108,479.
7
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 2001 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 2001 Annual Report on
Form 10-K and is available upon request from the Trustee.
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 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.
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
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
was formerly known as The Chase Manhattan Bank and is successor by mergers to
the original name of the Trustee, Texas Commerce Bank National Association).
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)
(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 first quarter of 2002.
9
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.
MESA OFFSHORE TRUST
By: /S/ JPMORGAN CHASE BANK, as Trustee
By: /s/ MIKE ULRICH
------------------------------------------------
MIKE ULRICH
VICE PRESIDENT
Date: April 24, 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.
10