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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 JUNE 30, 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.)
THE CHASE MANHATTAN BANK
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 August 8, 2000 -- 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- ------------------------
2000 1999 2000 1999
--------- ---------- ---------- ----------
Royalty income....................... $ 622,981 $2,288,525 $1,937,404 $2,288,525
Interest income...................... 30,551 29,279 63,867 48,427
General and administrative expense... (194,447) (358,955) (271,491) (378,103)
--------- ---------- ---------- ----------
Distributable income............ $ 459,085 $1,958,849 $1,729,780 $1,958,849
========= ========== ========== ==========
Distributable income per unit... $ .0064 $ .0272 $ .0240 $ .0272
========= ========== ========== ==========
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
JUNE 30, DECEMBER 31,
2000 1999
------------- -------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 2,428,534 $ 2,394,446
Interest receivable.................. 30,551 28,636
Net overriding royalty interest in
oil and gas properties............. 380,905,000 380,905,000
Accumulated amortization............. (380,885,615) (380,872,364)
------------- -------------
$ 2,478,470 $ 2,455,718
============= =============
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses........... $ 2,000,000 $ 2,000,000
Distributions payable................ 459,085 423,082
Trust corpus (71,980,216 units of
beneficial interest authorized and
outstanding)....................... 19,385 32,636
------------- -------------
$ 2,478,470 $ 2,455,718
============= =============
(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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ --------------------------
2000 1999 2000 1999
--------- ----------- ----------- -----------
Trust corpus, beginning of period.... $ 23,646 $ 56,401 $ 32,636 $ 56,401
Distributable income................. 459,085 1,958,849 1,729,780 1,958,849
Distributions to unitholders......... (459,085) (1,958,849) (1,729,780) (1,958,849)
Amortization of net overriding
royalty interest................... (4,261) (17,240) (13,251) (17,240)
--------- ----------- ----------- -----------
Trust corpus, end of period.......... $ 19,385 $ 39,161 $ 19,385 $ 39,161
========= =========== =========== ===========
(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 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 The
Chase Manhattan Bank (the "Trustee") 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 1999 Annual Report on Form
10-K.
3
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 any 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 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.
NOTE 3 -- RELEASE OF MMS ROYALTY RESERVE
During the mid-1980's, PNR withheld approximately $3.5 million ($3.1
million net to the Trust) as a reserve for potential liabilities for royalty
claims made by the Mineral Management Service ("MMS"). The claims by the MMS
included, among other things, disputed transportation allowances attributable to
the Trust's South Marsh Island properties and payments received by PNR from
purchasers as settlements under gas purchase contracts. During 1998, PNR settled
all known claims with the MMS for $3.6 million ($3.2 million net to the Trust)
which significantly reduced the amount in the reserve. The balance of the
reserve, including accrued interest, was approximately $3.4 million ($3.1
million net to the Trust). In May 1999, PNR determined that this reserve was no
longer necessary. Approximately $3.1 million was released to the Trust, subject
to the recovery of an approximate $1.0 million cost carryforward, and included,
net of amounts used to replenish the reserve for Trust expenses, in the second
quarter of 1999 distribution.
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. 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 second quarter of 2000, the Trust had distributable income of
$459,085, representing $.0064 per unit, as compared to $1,958,849, representing
$.0272 per unit in the second quarter of 1999. The per unit amounts of
distributable income for the second quarter of 2000 and 1999 were earned by
month as follows:
2000 1999
------ ------
April................................ $.0036 $ --
May.................................. .0019 .0270
June................................. .0009 .0002
------ ------
$.0064 $.0272
====== ======
Royalty income decreased to $622,981 in the second quarter of 2000 as
compared to $2,288,525 in the second quarter of 1999. The decrease in Royalty
income is primarily due to the release of amounts previously withheld by PNR
relating to potential liabilities for royalty claims of approximately
$3.1 million ($2.1 million net of deficit) in the second quarter of 1999. See
'Operational Review." However, excluding this one-time payment from Pioneer,
royalty income would have increased as compared to second quarter 1999. This is
due to higher production volumes on West Delta blocks 61 and 62 and increased
prices for natural gas and crude oil, condensate and natural gas liquids in the
second quarter of 2000 when compared to the corresponding 1999 period. In
addition, during the second quarter of 1999, the Trust recovered approximately
$140,500 in administrative expenses paid from the Trust's reserve fund during
the 1998 period in which Royalty income was not paid to the Trust, replenishing
the Trust's expense reserve fund balance to $2.0 million. This recovery
decreased second quarter of 1999 distributable income.
Production volumes for natural gas increased to 218,889 Mcf in the second
quarter of 2000 from 186,466 Mcf in the second quarter of 1999. The average
price received for natural gas was $2.63 per Mcf in the second quarter of 2000
as compared to $1.58 per Mcf in the second quarter of 1999.
Crude oil, condensate and natural gas liquids production increased to
11,709 barrels in the second quarter of 2000 from 2,212 barrels in the second
quarter of 1999. The average price received for crude oil, condensate and
natural gas liquids was $27.33 per barrel in the second quarter of 2000,
compared to $9.34 per barrel in the second quarter of 1999.
The increase in natural gas and crude oil, condensate and natural gas
liquids production for both the six months and the quarter ended June 30, 2000
when compared to the comparable periods of 1999 are primarily attributable to
successful farmouts on West Delta blocks 61 and 62.
5
For the six months ended June 30, 2000, natural gas production volumes
increased to 646,852 Mcf from 462,586 Mcf for the six months ended June 30,
1999. The average price received for natural gas was $2.79 per Mcf for the six
months ended June 30, 2000 compared to $1.66 per Mcf for the six months ended
June 30, 1999. Crude oil, condensate and natural gas liquids production volumes
increased to 34,389 barrels in the first six months of 2000 as compared to 8,002
barrels in the first six months of 1999. The average price received for crude
oil, condensate and natural gas liquids was $24.24 per barrel for the six months
ended June 30, 2000 compared to $10.49 per barrel for the six months ended
June 30,1999.
OPERATIONAL REVIEW
During the mid-1980's, PNR withheld approximately $3.5 million
($3.1 million net to the Trust) as a reserve for potential liabilities for
royalty claims made by the MMS. The claims by the MMS included, among other
things, disputed transportation allowances attributable to the Trust's South
Marsh Island properties and payments received by PNR from purchasers as
settlements under gas purchase contracts. During 1998, PNR settled all known
claims with the MMS for $3.6 million ($3.2 million net to the Trust) which
significantly reduced the amount in the reserve. The balance of the reserve,
including accrued interest, was approximately $3.4 million ($3.1 million net to
the Trust). In May 1999, PNR determined that this reserve was no longer
necessary. Approximately $3.1 million was released to the Trust, subject to the
recovery of an approximate $1.0 million cost carryforward, and included, net of
amounts used to replenish the reserve for Trust expenses, in the second quarter
of 1999 distribution.
PNR has advised the Trust that during the second 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 continue to market its
production under short-term contracts for the foreseeable future. Spot market
prices for natural gas in the second quarter of 2000 were generally higher than
spot market prices in the second 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.
Natural gas and condensate production on the Brazos A-7 and A-39 blocks
remained essentially unchanged during the second quarter of 2000 as compared to
the same period in 1999. 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. During the second
quarter of 2000, PNR farmed out an additional Trust portion of the Brazos A-7
block. A successful exploratory well was completed and began producing in July
2000. The Trust will have a 4.5% overriding royalty interest in this discovery.
Including this new well, the combined blocks are currently producing at a rate
of 9 MMcf and 25 barrels of condensate per day.
The South Marsh Island 155 and 156 blocks ceased production in March 2000.
Four workovers were performed in late 1999 and early 2000 to attempt to restore
production. While two workovers were successful in restoring production for a
short period, the well ceased production shortly thereafter. 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. However, PNR is
investigating the possibility of farming out the blocks to another operator who
wishes to drill an exploratory well and would retain an overriding royalty
interest.
6
The West Delta 61 and 62 blocks experienced an increase in oil and in
natural gas production in the second quarter of 2000 as compared to the second
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 4 MMcf and 1,000 barrels
of condensate per day.
Matagorda Island 624 production continued to decrease in the second quarter
of 2000 as compared to the second quarter of 1999, primarily due to natural
production decline. Gross production for the block is currently 0.8 MMcf per day
as of August 2000.
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 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 activities, 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
7
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
The following tables provide a summary of the calculations of the net
proceeds attributable to the Partnership's royalty interest:
SOUTH
BRAZOS MARSH WEST
A-7 AND ISLAND 155 DELTA 61 MATAGORDA
A-39 AND 156 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 (excess costs)...... $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
THREE MONTHS ENDED JUNE 30, 1999:
Ninety percent of gross
proceeds....................... $228,808 $ (10,210) $ -- $ 96,248 $ 314,846
Release of MMS royalty reserve... -- 2,116,594 -- -- $2,116,594
Less ninety percent of --
Operating expenditures......... (73,857) 26,966 (73,340) 12,119 (108,112)
Capital costs recovered........ (420) -- -- (858) (1,278)
Accrual for future abandonment
costs and interest on cost
carryforward................ -- (33,296) -- -- (33,296)
-------- ---------- -------- -------- ----------
Net proceeds..................... $154,531 $2,100,054 $(73,340) $107,509 $2,288,754
======== ========== ======== ======== ==========
Trust share of net proceeds
(99.99%)....................... $2,288,525
==========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 346 758 -- 1,108 2,212
======== ========== ======== ======== ==========
Average sales price per Bbl.... $ 11.07 $ 6.67 $ -- $ 10.64 $ 9.34
======== ========== ======== ======== ==========
Natural gas (Mcf).............. 135,804 -- -- 50,662 186,466
======== ========== ======== ======== ==========
Average sales price per Mcf.... $ 1.66 $ -- $ -- $ 1.67 $ 1.58
======== ========== ======== ======== ==========
Producing wells.................. 4 2 3 1 10
- ------------
o The amounts shown are for Mesa Offshore Royalty Partnership.
o The amounts for the three months ended June 30, 2000 and 1999 represent actual
production for the periods February 2000 through April 2000 and February 1999
through April 1999, respectively.
o Gross proceeds for South Marsh Island 155 and 156 for the three months ended
June 30, 1999 include certain prior period adjustments.
o The release of MMS royalty reserve at June 30, 1999 represents the cost
carryforward of $1.0 million, of which $0.7 million primarily related to well
completion costs on the Brazos A-7 No. 5 and other unrecovered capital costs,
and $0.3 million related to over distributions by Pioneer over the twelve
months ending December 31, 1998, netted against the payment of amounts
previously withheld by Pioneer relating to potential liabilities for royalty
claims of $3.1 million.
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 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 late 1999, the Trust began receiving revenues due
to successful farm outs of new wells.
9
SOUTH
BRAZOS MARSH WEST
A-7 AND ISLAND 155 DELTA 61 MATAGORDA
A-39 AND 156 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
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 (excess costs)...... $ 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
SOUTH
BRAZOS MARSH WEST
A-7 AND ISLAND 155 DELTA 61 MATAGORDA
A-39 AND 156 AND 62 ISLAND 624 TOTAL
---------- ----------- ---------- ---------- ----------
SIX MONTHS ENDED JUNE 30, 1999:
Ninety percent of gross
proceeds....................... $ 630,203 $ 63,603 $ (6,900) $ 163,660 $ 850,566
Release of MMS royalty reserve... -- 2,116,594 -- -- 2,116,594
Less ninety percent of --
Operating expenditures......... (187,995) (139,203) (251,097) (37,296) (615,591)
Capital costs recovered........ (3,894) -- -- (5,625) (9,519)
Accrual for future abandonment
costs.......................... (11,727) (34,796) (5,848) (925) (53,296)
---------- ----------- ---------- --------- ----------
Net proceeds..................... $ 426,587 $ 2,006,198 $ (263,845) $ 119,814 $2,288,754
========== =========== ========== ========= ==========
Trust share of net proceeds
(99.99%)....................... $2,288,525
==========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... (24) 6,368 -- 1,658 8,002
========== =========== ========== ========= ==========
Average sales price per Bbl.... $ (27.78) $ 10.26 $ -- $ 10.84 $ 10.49
========== =========== ========== ========= ==========
Natural gas (Mcf).............. 355,587 27,440 (3,039) 82,598 462,586
========== =========== ========== ========= ==========
Average sales price per Mcf.... $ 1.77 $ (0.06) $ 2.27 $ 1.76 $ 1.66
========== =========== ========== ========= ==========
Producing wells.................. 4 2 3 1 10
- ------------
o The amounts shown are for Mesa Offshore Royalty Partnership.
o The amounts for the six months ended June 30, 2000 and 1999 represent actual
production for the periods November 1999 through April 2000, and November 1998
through April 1999 respectively.
o Gross proceeds for West Delta 61 and 62 for the six months ended June 30, 2000
include certain prior period adjustments. 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 late 1999,
the Trust began receiving revenues due to successful farm outs of new wells.
o The release of MMS royalty reserve at June 30, 1999 represents the cost
carryforward of $1.0 million, of which $0.7 million primarily related to well
completion costs on the Brazos A-7 No. 5 and other unrecovered capital costs,
and $0.3 million related to over distributions by Pioneer over the twelve
months ending December 31, 1998, netted against the payment of amounts
previously withheld by Pioneer relating to potential liabilities for royalty
claims of $3.1 million.
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.
10
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.)
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)
27 Financial Data Schedule
(B) REPORTS ON FORM 8-K
None.
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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 THE CHASE MANHATTAN BANK
--------------------------------------
TRUSTEE
By /s/ PETE FOSTER
--------------------------------------
PETE FOSTER
SENIOR VICE PRESIDENT & TRUST OFFICER
Date: August 8, 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.
12