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 SEPTEMBER 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.)
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 November 9, 2000 -- 71,980,216 Units of Beneficial Interest in Mesa
Offshore Trust.
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------- ------------------------
2000 1999 2000 1999
--------- -------- ---------- ----------
Royalty income....................... $ 461,949 $588,131 $2,399,353 $2,876,656
Interest income...................... 56,502 23,872 120,369 72,299
General and administrative expense... (101,937) (41,323) (373,428) (419,426)
--------- -------- ---------- ----------
Distributable income............ $ 416,514 $570,680 $2,146,294 $2,529,529
========= ======== ========== ==========
Distributable income per unit... $ .0058 $ .0079 $ .0298 $ .0351
========= ======== ========== ==========
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
SEPTEMBER 30, DECEMBER 31,
2000 1999
------------- -------------
(UNAUDITED)
ASSETS
Cash and short-term investments. $ 2,360,012 $ 2,394,446
Interest receivable.................. 56,502 28,636
Net overriding royalty interest in
oil and gas properties............. 380,905,000 380,905,000
Accumulated amortization............. (380,888,774) (380,872,364)
------------- -------------
$ 2,432,740 $ 2,455,718
============= =============
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses. $ 2,000,000 $ 2,000,000
Distributions payable................ 416,514 423,082
Trust corpus (71,980,216 units of
beneficial interest authorized
and outstanding)................... 16,226 32,636
------------- -------------
$ 2,432,740 $ 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------- --------------------------
2000 1999 2000 1999
--------- --------- ----------- -----------
Trust corpus, beginning of period.... $ 19,385 $ 39,161 $ 32,636 $ 56,401
Distributable income............ 416,514 570,680 2,146,294 2,529,529
Distributions to unitholders.... (416,514) (570,680) (2,146,294) (2,529,529)
Amortization of net overriding
royalty interest.............. (3,159) (2,853) (16,410) (20,093)
--------- --------- ----------- -----------
Trust corpus, end of period.......... $ 16,226 $ 36,308 $ 16,226 $ 36,308
========= ========= =========== ===========
(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
future 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"), the successor by merger to the Chase Bank
of Texas, National Association, in accordance with the instructions to Form
10-Q, and the Trustee believes such information includes all the disclosures
necessary to make the information presented not misleading. The information
furnished reflects all adjustments which are, in the opinion of the Trustee,
necessary for a fair presentation of the results for the interim periods
presented. The financial information should be read in conjunction with the
financial statements and notes thereto included in the Trust's 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 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 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.
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 third quarter of 2000, the Trust had distributable income of
$416,514, representing $.0058 per unit, as compared to $570,680, representing
$.0079 per unit in the second quarter of 1999. The per unit amounts of
distributable income for the third quarter of 2000 and 1999 were earned by month
as follows:
2000 1999
------ ------
July................................. $.0012 $ --
August............................... .0006 --
September............................ .0040 .0079
------ ------
$.0058 $.0079
====== ======
Royalty income decreased to $461,949 in the third quarter of 2000 as
compared to $588,131 in the third quarter of 1999. The decrease in Royalty
income is primarily due to the decrease in natural gas production partially
offset by increases in natural gas, crude oil and condensate prices. See
"Operational Review."
Production volumes for natural gas decreased to 117,025 Mcf in the third
quarter of 2000 from 392,036 Mcf in the third quarter of 1999 primarily as a
result of decreased production on West Delta 61 and 62 and Brazos A-7 and A-39.
The average price received for natural gas was $3.46 per Mcf in the third
quarter of 2000 compared to $2.22 per Mcf in the third quarter of 1999.
Crude oil, condensate and natural gas liquids production increased slightly
to 10,464 barrels in the third quarter of 2000 from 10,028 barrels in the third
quarter of 1999. The average price received for crude oil, condensate and
natural gas liquids was $29.29 per barrel in the third quarter of 2000, compared
to $16.09 per barrel in the third quarter of 1999.
For the nine months ended September 30, 2000, natural gas production
volumes decreased to 763,875 Mcf from 854,622 Mcf for the nine months ended
September 30, 1999. The average price received for natural gas was $2.89 per Mcf
for the nine months ended September 30, 2000 compared to $1.92 for the nine
months ended September 30, 1999. Crude oil, condensate and natural gas liquids
production volumes increased to 44,852 barrels in the first nine months of 2000
as compared to 18,030 barrels in the first nine months of 1999. The average
price received for crude oil, condensate and natural gas liquids was $25.42 per
barrel for the nine months ended September 30, 2000 compared to $13.60 per
barrel for the nine months ended September 30, 1999.
5
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 third 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 third quarter of 2000 were generally higher than
spot market prices in the third 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 of the Brazos A-7 and A-39 blocks
decreased during the third quarter of 2000 as compared to the same period in
1999 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. 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 2.5 MMcf and 6 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.
The West Delta 61 and 62 blocks experienced a decrease in oil and natural
gas production in the third quarter of 2000 as compared to the third quarter of
1999 primarily due to production from farmout agreements occurring in late 1999
and early 2000. However, due to the timing of the production from the farmout
agreements oil and natural gas production has increased for the nine months
ending September 30, 2000 compared to the nine months ending September 30, 1999.
In portions of West Delta block 62, the Trust is receiving Royalty income from
this property 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
6
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 3 MMcf and 700 barrels of condensate per day.
Matagorda Island 624 oil and natural gas production continued to decrease
in the third quarter of 2000 as compared to the third quarter of 1999, primarily
due to natural production decline. Gross production from the block is currently
approximately 0.3 MMcf of gas and 6 barrels of condensate per day.
TERMINATION OF THE TRUST
The terms of the Mesa Offshore Trust Indenture provide, among other things
that the Trust will terminate upon the first to occur of the following events:
(1) the total amount of cash received per year by the Trust for each of three
successive years commencing after December 31, 1987 is less than 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, 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 $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 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
The following tables provide summaries of the calculations of the net
proceeds attributable to the Partnership's royalty interests (unaudited):
SOUTH
BRAZOS MARSH WEST MATAGORDA
A-7 AND ISLAND 155 DELTA 61 ISLAND
A-39 AND 156 AND 62 624 TOTAL
--------- ---------- -------- ---------- ----------
THREE MONTHS ENDED
SEPTEMBER 30, 2000:
Ninety percent of gross
proceeds....................... $ 331,870 $ 1,394 $330,346 $ 47,314 $ 710,924
Less ninety percent of --
Operating expenditures......... (84,722) (22,121) (97,500) (14,586) (218,929)
Capital costs recovered........ -- -- -- -- --
Accrual for future abandonment
costs....................... (16,059) (62) (11,794) (2,085) (30,000)
--------- --------- -------- -------- ----------
Net proceeds (excess costs)...... $ 231,089 $ (20,789) $221,052 $ 30,643 $ 461,995
========= ========= ======== ======== ==========
Trust share of net proceeds
(99.99%)....................... $ 461,949
==========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 359 48 9,742 315 10,464
========= ========= ======== ======== ==========
Average sales price per Bbl.... $ 27.09 $ 26.73 $ 29.49 $ 25.98 $ 29.29
========= ========= ======== ======== ==========
Natural gas (Mcf).............. 94,099 82 12,236 10,608 117,025
========= ========= ======== ======== ==========
Average sales price per Mcf.... $ 3.42 $ 1.51 $ 3.52 $ 3.69 $ 3.46
========= ========= ======== ======== ==========
Producing wells.................. 3 -- 3 1 7
SOUTH
BRAZOS MARSH WEST MATAGORDA
A-7 AND ISLAND 155 DELTA 61 ISLAND
A-39 AND 156 AND 62 624 TOTAL
--------- ---------- --------- ---------- ----------
THREE MONTHS ENDED
SEPTEMBER 30, 1999:
Ninety percent of gross
proceeds....................... $ 321,079 $ 11,081 $ 623,737 $ 76,797 $1,032,694
Less ninety percent of --
Operating expenditures......... (103,601) (139,267) (64,680) (75,293) (382,841)
Capital costs recovered........ (205) (61,458) -- -- (61,663)
Accrual for future abandonment
costs....................... -- -- -- -- --
--------- ---------- --------- -------- ----------
Net proceeds (excess costs)...... $ 217,273 $ (189,644) $ 559,057 $ 1,504 $ 588,190
========= ========== ========= ======== ==========
Trust share of net proceeds
(99.99%)....................... $ 588,131
==========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 326 1,151 8,191 360 10,028
========= ========== ========= ======== ==========
Average sales price per Bbl.... $ 14.40 $ 14.69 $ 16.41 $ 14.83 $ 16.09
========= ========== ========= ======== ==========
Natural gas (Mcf).............. 151,452 70 200,756 39,758 392,036
========= ========== ========= ======== ==========
Average sales price per Mcf.... $ 2.09 $ -- $ 2.44 $ 1.80 $ 2.22
========= ========== ========= ======== ==========
Producing wells.................. 4 -- 3 1 8
- ------------
o The amounts shown are for Mesa Offshore Royalty Partnership.
o The amounts for the three months ended September 30, 2000 and 1999 represent
actual production for the periods May 2000 through July 2000 and May 1999
through July 1999, respectively.
o Capital costs recovered represent 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.
8
SOUTH
BRAZOS MARSH WEST
A-7 AND ISLAND 155 DELTA 61 MATAGORDA
A-39 AND 156 AND 62 ISLAND 624 TOTAL
---------- ---------- ---------- ---------- ----------
NINE MONTHS ENDED
SEPTEMBER 30, 2000:
Ninety percent of gross
proceeds....................... $1,044,852 $ 93,095 $2,023,387 $ 185,569 $3,346,903
Less ninety percent of --
Operating expenditures......... (263,937) (205,137) (232,737) (90,240) (792,051)
Capital costs recovered........ -- (95,259) -- -- (95,259)
Accrual for future abandonment
costs....................... (30,481) (11,557) (13,410) (4,552) (60,000)
---------- ---------- ---------- --------- ----------
Net proceeds (excess costs)...... $ 750,434 $ (218,858) $1,777,240 $ 90,777 $2,399,593
========== ========== ========== ========= ==========
Trust share of net proceeds
(99.99%)....................... $2,399,353
==========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 975 593 42,282 1,002 44,852
========== ========== ========== ========= ==========
Average sales price per Bbl.... $ 26.10 $ 26.48 $ 25.35 $ 27.11 $ 25.42
========== ========== ========== ========= ==========
Natural gas (Mcf).............. 360,707 33,457 315,790 53,921 763,875
========== ========== ========== ========= ==========
Average sales price per Mcf.... $ 2.83 $ 2.31 $ 3.01 $ 2.94 $ 2.89
========== ========== ========== ========= ==========
Producing wells.................. 3 -- 3 1 7
SOUTH
BRAZOS MARSH WEST
A-7 AND ISLAND 155 DELTA 61 MATAGORDA
A-39 AND 156 AND 62 ISLAND 624 TOTAL
-------- ---------- -------- ---------- ----------
NINE MONTHS ENDED
SEPTEMBER 30, 1999:
Ninety percent of gross
proceeds....................... $951,282 $ 74,684 $616,837 $ 240,457 $1,883,260
Release of MMS royalty reserve... -- 2,116,594 -- -- 2,116,594
Less ninety percent of --
Operating expenditures......... (291,596) (278,470) (315,777) (112,589) (998,432)
Capital costs recovered........ (4,099) (61,458) -- (5,625) (71,182)
Accrual for future abandonment
costs.......................... (11,727) (34,796) (5,848) (925) (53,296)
-------- ---------- -------- --------- ----------
Net proceeds (excess costs)...... $643,860 $1,816,554 $295,212 $ 121,318 $2,876,944
======== ========== ======== ========= ==========
Trust share of net proceeds
(99.99%)....................... $2,876,656
==========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 302 7,519 8,191 2,018 18,030
======== ========== ======== ========= ==========
Average sales price per Bbl.... $ 17.85 $ 10.94 $ 16.41 $ 11.55 $ 13.60
======== ========== ======== ========= ==========
Natural gas (Mcf).............. 507,039 27,510 197,717 122,356 854,622
======== ========== ======== ========= ==========
Average sales price per Mcf.... $ 1.87 $ (0.27) $ 2.44 $ 1.77 $ 1.92
======== ========== ======== ========= ==========
Producing wells.................. 4 -- 3 1 8
- ------------
o The amounts shown are for Mesa Offshore Royalty Partnership.
o The amounts for the nine months ended September 30, 2000 and 1999 represent
actual production for the periods November 1999 through July 2000, and
November 1998 through July 1999, respectively.
o Capital costs recovered represent 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 being incurred for maintenance
procedures. In late 1999, the Trust began receiving revenues due to successful
farmouts of new wells.
o The release of MMS royalty reserve at September 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.
9
PART II
ITEM 6. EXHIBIT 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
Limited Partnership 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.
10
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: November 13, 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.
11