================================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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 MARCH 31,2000
[ ] 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
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.)
CHASE BANK OF TEXAS,
NATIONAL ASSOCIATION
CORPORATE TRUST DIVISION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
1-800-852-1422
(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 May 10, 2000 -- 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)
THREE MONTHS ENDED
MARCH 31,
------------------------
2000 1999
------------ ----------
Royalty income....................... $ 1,314,423 $ --
Interest income...................... 33,316 19,148
General and administrative expense... (77,044) (19,148)
------------ ----------
Distributable income............ $ 1,270,695 $ --
============ ==========
Distributable income per unit... $ .0177 $ --
============ ==========
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
MARCH 31, DECEMBER 31,
2000 1999
---------------- ----------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 3,237,379 $ 2,394,446
Interest receivable.................. 33,316 28,636
Net overriding royalty interest in
oil and gas properties............. 380,905,000 380,905,000
Accumulated amortization............. (380,881,354) (380,872,364)
---------------- ----------------
$ 3,294,341 $ 2,455,718
================ ================
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses........... $ 2,000,000 $ 2,000,000
Distributions payable................ 1,270,695 423,082
Trust corpus (71,980,216 units of
beneficial interest authorized and
outstanding)....................... 23,646 32,636
---------------- ----------------
$ 3,294,341 $ 2,455,718
================ ================
(The accompanying notes are an integral part of these financial statements.)
1
<PAGE>
MESA OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
-----------------------
2000 1999
------------ ---------
Trust corpus, beginning of period.... $ 32,636 $ 56,401
Distributable income................. 1,270,695 --
Distributions to unitholders......... (1,270,695) --
Amortization of net overriding
royalty interest................... (8,990) --
------------ ---------
Trust corpus, end of period.......... $ 23,646 $ 56,401
============ =========
(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,
1999 reserve report prepared for the Partnership (see the Trust's 1999 Annual
Report on Form 10-K) indicates that Royalty income expected to be received by
the Trust in 2001 and thereafter could be at or near the Termination Threshold.
The reserve report estimates that future Royalty income to the Trust is
approximately $4.8 million while the Termination Threshold for 1999 was
approximately $1.4 million. It is therefore possible (depending on the timing of
production, market conditions, success of future drilling activity, if any, and
other matters) that in 2001 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. 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. 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 2001 or thereafter will be above the Termination Threshold.
NOTE 2 -- BASIS OF PRESENTATION
The accompanying unaudited financial information has been prepared by Chase
Bank of Texas, National Association (the "Trustee") 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 1999 Annual
Report on Form 10-K.
3
<PAGE>
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.
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 for the first quarter of 2000, was $1,270,695,
representing $.0177 per unit, as compared to no distributable income in the
first quarter of 1999 due to the recovery of capital costs associated with
completion costs on the Brazos A-7 No. B-1 well. Such costs were recovered in
the second quarter of 1999. The per unit amounts of distributable income for the
first quarter of 2000 and 1999 were earned by month as follows:
2000 1999
--------- ---------
January.............................. $ .0108 $ --
February............................. .0042 --
March................................ .0027 --
--------- ---------
$ .0177 $ --
========= =========
Royalty income was $1,314,423 in the first quarter of 2000 as compared to
no royalty income for the first quarter of 1999. Royalty income in the first
quarter increased when compared to the fourth quarter of 1999 due to increased
production volumes on West Delta 61 and 62 blocks and increased prices for
natural gas and crude oil, condensate and natural gas liquids in 2000.
Production volumes for natural gas increased to 427,963 Mcf in the first
quarter of 2000 from 276,120 Mcf in the first quarter of 1999. The average price
received for natural gas was $2.86 per Mcf in the first quarter of 2000 as
compared to $1.71 per Mcf in the first quarter of 1999.
Crude oil, condensate and natural gas liquids production increased to
22,680 barrels in the first quarter of 2000 from 5,791 barrels in the first
quarter of 1999. The average price received for crude oil, condensate and
natural gas liquids was $22.64 per barrel in the first quarter of 2000, as
compared to $10.93 per barrel in the first quarter of 1999.
The increase in natural gas and crude oil, condensate and natural gas
liquids production in the first quarter of 2000 as compared to the first quarter
of 1999 was primarily attributable to successful farmouts on West Delta 61 and
62 blocks.
OPERATIONAL REVIEW
PNR has advised the Trust that during the first quarter of 2000 its
offshore gas production was marketed under short-term contracts at spot market
prices primarily to H&N, Limited and that it expects to
5
<PAGE>
continue to market its production under short-term contracts for the foreseeable
future. Spot market prices for natural gas in the first quarter of 2000 were
generally higher than spot market prices in the first quarter of 1999.
The amount of cash distributed by the Trust is dependent on, among other
things, the sales prices and quantities of gas, crude oil, condensate and
natural gas liquids produced from the Royalty Properties and the quantities
sold. Substantial uncertainties exist with regard to future gas and oil prices,
which are subject to fluctuations due to the regional supply and demand for
natural gas and oil, production levels and other activities of the Organization
of the Petroleum Exporting Countries ("OPEC") and other oil and gas producers,
weather, storage levels, industrial growth, conservation measures, competition
and other variables.
The Brazos A-7 and A-39 blocks experienced a decrease in natural gas
production in the first quarter of 2000 as compared to the first quarter of 1999
primarily due to natural production decline. PNR farmed out a portion of the
Brazos A-7 block to another operator 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 9.3 MMcf and 16 barrels of
condensate per day.
The South Marsh Island 155 and 156 blocks are currently not producing. 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. In 1998, PNR purchased 3-D seismic data for
the South Marsh Island 156 block at a cost of $300,000 ($189,000 net to the
Trust). The data has been evaluated, but PNR has no current plans for additional
drilling or recompletions.
The West Delta 61 and 62 blocks experienced an increase in oil and natural
gas production in the first quarter of 2000 as compared to the first quarter of
1999 primarily due to new production from farmout agreements. In portions of
West Delta block 62, the Trust is receiving Royalty income pursuant to a farmout
agreement with another operator. The interest in the farmout wells that is
attributable to the Trust consists of a 7.5% net profits interest. In West Delta
block 61, PNR farmed out portions of the block to another operator, retaining a
12.5% (11.25% net to the Trust) overriding royalty interest. The operator has
drilled 3 exploratory wells, 2 of which were successful. The 2 successful wells
began producing during the second quarter of 1999 and are currently producing at
a combined rate of approximately 14.6 MMcf and 1,400 barrels of condensate per
day.
Matagorda Island 624 production continued to decrease in the first quarter
of 2000 as compared to the first quarter of 1999, primarily due to natural
production decline. Gross production for the block is currently 1.1 MMcf per day
and 16 barrels of condensate per day as of May 2000 compared to 1 MMcf per day
and 19 barrels of condensate per day as of May 1999.
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 10 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 the unitholders 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
6
<PAGE>
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 1999
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 available upon request from
the Trustee.
Amounts paid to the Trustee as compensation were, $132,000, $128,000 and
$173,000 for the years 1999, 1998 and 1997, respectively.
The December 31, 1999 reserve report prepared for the Partnership indicates
that Royalty income expected to be received by the Trust in 2001 and thereafter
could be at or near the Termination Threshold. The reserve report estimates that
future Royalty income to the Trust is approximately $4.8 million, while the
Termination Threshold for 1999 was approximately $1.4 million. It is therefore
possible (depending on the timing of production, market conditions, success of
future drilling activity, if any, and other matters) that in 2001 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 2001 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.
7
<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
BRAZOS MARSH WEST
A-7 AND ISLAND 155 DELTA 61 MATAGORDA
A-39 AND 156 AND 62 ISLAND 624 TOTAL
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
THREE MONTHS ENDED MARCH 31, 2000
Ninety percent of gross
proceeds....................... $ 351,117 $ 48,599 $1,273,721 $ 66,013 $1,739.450
Less ninety percent of --
Operating expenditures......... (100,777) (138,309) (73,700) (50,177) (362,963)
Capital costs recovered........ -- (61,933) -- -- (61,933)
Accrual for future abandonment
costs........................ -- -- -- -- --
---------- ---------- ---------- ---------- ----------
Net proceeds..................... $ 250,340 $ (151,643) $1,200,021 $ 15,836 $1,314,554
========== ========== ========== ========== ==========
Trust share of net proceeds
(99.99%)....................... $1,314,423
==========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids (Bbls)... 234 23 20,022 401 22,680
========== ========== ========== ========== ==========
Average sales price per Bbl.... $ 23.75 $ 20.20 $ 22.62 $ 23.15 $ 22.64
========== ========== ========== ========== ==========
Natural gas (Mcf).............. 129,898 20,938 255,879 21,248 427,963
========== ========== ========== ========== ==========
Average sales price per Mcf.... $ 2.66 $ 2.30 $ 3.03 $ 2.67 $ 2.86
========== ========== ========== ========== ==========
Producing wells................ 4 -- 3 1 8
========== ========== ========== ========== ==========
THREE MONTHS ENDED MARCH 31, 1999:
Ninety percent of gross
proceeds....................... $ 401,395 $ 73,813 $ (6,900) $ 67,412 $ 535,720
Less ninety percent of --
Operating expenditures......... (114,138) (166,169) (177,757) (49,415) (507,479)
Capital costs recovered........ (3,474) -- -- (4,767) (8,241)
Accrual for future abandonment
costs and interest on cost
carryforward................. (11,727) (1,500) (5,848) (925) (20,000)
---------- ---------- ---------- ---------- ----------
Net proceeds (excess costs)...... $ 272,056 $ (93,856) $ (190,505) $ 12,305 $ --
========== ========== ========== ========== ==========
Trust share of net proceeds
(99.99%)....................... $ --
==========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids (Bbls)... (370) 5,610 -- 551 5,791
========== ========== ========== ========== ==========
Average sales price per Bbl.... $ 8.48 $ 10.74 $ -- $ 11.24 $ 10.93
========== ========== ========== ========== ==========
Natural gas (Mcf).............. 219,783 27,440 (3,039) 31,936 276,120
========== ========== ========== ========== ==========
Average sales price per Mcf.... $ 1.84 $ 0.49 $ 2.27 $ 1.92 $ 1.71
========== ========== ========== ========== ==========
Producing wells.................. 4 2 3 1 10
</TABLE>
- ------------
o The amounts shown are for Mesa Offshore Royalty Partnership.
o The amounts for the three months ended March 31, 2000 and 1999 represent
actual production for the periods November 1999 through January 2000 and
November 1998 through January 1999, respectively.
o 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.
o Producing wells indicate the number of wells capable of production as of the
end of the period.
o At March 31, 1999, the cost carryforward was $1.0 million, of which $0.7
million primarily related to well completion costs on the Brazos A-7 No. B-1
(formerly No. 5) and other unrecovered capital costs and $0.3 million
related to overpayments by Pioneer during the twelve months ending December
31, 1998.
o West Delta 61 and 62 ceased production in the second quarter of 1998 through
mid 1999. However, operating expenses were still being incurred for
maintenance procedures. In 1999, the Trust began receiving revenues due to
successful farm outs of new wells.
8
<PAGE>
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. Chase Bank of Texas,
National Association is the successor name of Texas Commerce Bank National
Association.)
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
<C> <S> <C> <C>
4(a) *Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas
Commerce Bank National Association, as Trustee, dated December 15,
1982.................................................................... 2-79673 10(gg)
4(b) *Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa
Offshore Royalty Partnership, dated December 15, 1982................... 2-79673 10(hh)
4(c) *Partnership Agreement between Mesa Offshore Management Co. and Texas
Commerce Bank National Association, as Trustee, dated December 15,
1982.................................................................... 2-79673 10(ii)
4(d) *Amendment to Partnership Agreement between Mesa Offshore Management Co.,
Texas Commerce Bank National Association, as Trustee, and Mesa Operating
Limited Partnership, dated December 27, 1985 (Exhibit 4(d) to Form 10-K
for year ended December 31, 1992 of Mesa Offshore Trust)................ 1-8432 4(d)
4(e) *Amendment to Partnership Agreement between Texas Commerce Bank National
Association, as Trustee and Mesa Operating dated as of January 5, 1994
(Exhibit 4(e) to Form 10-K for year ended December 31, 1993 of Mesa
Offshore Trust)......................................................... 1-8432 4(e)
27 Financial Data Schedule
</TABLE>
(B) REPORTS ON FORM 8-K
None.
9
<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.
MESA OFFSHORE TRUST
CHASE BANK OF TEXAS,
By NATIONAL ASSOCIATION
-----------------------------------
TRUSTEE
By /s/ PETE FOSTER
-----------------------------------
PETE FOSTER
SENIOR VICE PRESIDENT & TRUST
OFFICER
Date: May 10, 2000
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
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM MESA
OFFSHORE TRUST FORM 10-Q FOR THE QUARTERLY PERIOD ENDED 03/31/00 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-2000
<PERIOD-END> MAR-31-2000
<CASH> 3,237,379
<SECURITIES> 0
<RECEIVABLES> 33,316
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 0
<PP&E> 380,905,000
<DEPRECIATION> (380,881,354)
<TOTAL-ASSETS> 3,294,341
<CURRENT-LIABILITIES> 1,270,695
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 2,023,646
<TOTAL-LIABILITY-AND-EQUITY> 3,294,341
<SALES> 0
<TOTAL-REVENUES> 1,347,739
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 77,044
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 1,270,695
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1,270,695
<EPS-BASIC> .01
<EPS-DILUTED> .01
</TABLE>
