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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, 1999
[ ] 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 August 10, 1999 -- 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,
-------------------------- --------------------------
1999 1998 1999 1998
------------ ------------ ------------ ------------
Royalty income....................... $ 2,288,525 $ 440,956 $ 2,288,525 $ 1,135,274
Interest income...................... 29,279 27,824 48,427 55,581
General and administrative expense... (358,955) (144,574) (378,103) (206,990)
------------ ------------ ------------ ------------
Distributable income............ $ 1,958,849 $ 324,206 $ 1,958,849 $ 983,865
============ ============ ============ ============
Distributable income per unit... $ .0272 $ .0045 $ .0272 $ .0137
============ ============ ============ ============
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
JUNE 30, DECEMBER 31,
1999 1998
---------------- ----------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 3,929,570 $ 1,836,398
Interest receivable.................. 29,279 23,102
Net overriding royalty interest in
oil and gas properties............. 380,905,000 380,905,000
Accumulated amortization............. (380,865,839) (380,848,599)
---------------- ----------------
$ 3,998,010 $ 1,915,901
================ ================
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses........... $ 2,000,000 $ 1,859,500
Distributions payable................ 1,958,849 --
Trust corpus (71,980,216 units of
beneficial interest
authorized and outstanding)........ 39,161 56,401
---------------- ----------------
$ 3,998,010 $ 1,915,901
================ ================
(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,
--------------------------- ---------------------------
1999 1998 1999 1998
------------- ------------ ------------- ------------
Trust corpus, beginning of period.... $ 56,401 $ 168,742 $ 56,401 $ 248,200
Distributable income................. 1,958,849 324,206 1,958,849 983,865
Distributions to unitholders......... (1,958,849) (324,206) (1,958,849) (983,865)
Amortization of net overriding
royalty interest................... (17,240) (50,463) (17,240) (129,921)
------------- ------------ ------------- ------------
Trust corpus, end of period.......... $ 39,161 $ 118,279 $ 39,161 $ 118,279
============= ============ ============= ============
(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 when Mesa Petroleum Co., predecessor to Mesa Limited Partnership, which was
the predecessor to MESA Inc., transferred a 99.99% interest in the Mesa Offshore
Royalty Partnership (the "Partnership") to the Trust. The Partnership was
created to receive and hold a 90% 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"). Until
August 7, 1997, MESA Inc. owned and operated its assets through Mesa Operating
Co. ("Mesa"), the operator of the Royalty Properties. Mesa Operating Co. is also
the managing general partner of the Partnership (the Managing General Partners).
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 Operating Co.), 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,
1998 reserve report prepared for the Partnership (see the Trust's 1998 Annual
Report on Form 10-K) indicates that Royalty income expected to be received by
the Trust in 2000 could be at or near the Termination Threshold. The reserve
report estimates that future Royalty income to the Trust is approximately $5.2
million while the Termination Threshold for 1998 was approximately $1.4 million.
It is therefore possible (depending on the timing of future production and
drilling activities, market conditions, recoupment of unrecovered capital costs
and other matters) that in 2000 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. 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 2000 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 1998 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 PNR to the Partnership for such month rather
than either the value of a portion of the oil and gas produced by PNR 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 distribution date;
(c) Trust general and administrative expenses are recorded in the
month they are accrued;
(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, these statements differ from financial
statements prepared in accordance with generally accepted accounting principles
in several respects. 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 would include interest earned during
the period covered by the financial statements and would exclude interest from
the period end to the date of distribution.
The instruments conveying the Royalty provide that PNR 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 PNR 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.
STATUS OF PENDING COSTILLA SALE AGREEMENT
On April 15, 1999, Pioneer Natural Resources Company announced the
termination of the transaction contemplated by the April 1, 1999 Purchase and
Sales Agreement between PNR and Costilla Energy, Inc. providing for the sale of
certain oil and gas properties to Costilla. Included with the properties to be
sold were PNR's interest in all of the Royalty properties. PNR has executed a
contingency plan to remarket these properties. If such a sale is consummated,
the Trust has been advised that there should be no significant impact on the
Trust, although the precise nature of any effects cannot be predicted or
quantified at this time.
INFORMATION SYSTEMS FOR THE YEAR 2000
The inability of some computer programs and embedded computer chips to
distinguish between the year 1900 and the year 2000 (the "Year 2000 problem")
poses a serious threat of business disruption to any organization that utilized
computer technology and computer chip technology in their business systems or
equipment. In proactive response to the Year 2000 problem, PNR established a
"Year 2000" project to assess, to the extent possible, PNR's internal Year 2000
problem; to take remedial actions necessary to minimize the Year 2000 risk
exposure to PNR and significant third parties with whom it has data interchange;
and, to test its systems and processes once remedial actions have been taken.
PNR has contracted with IBM Global Services to perform the assessment and
remedial phases of its Year 2000 project.
As of June 30, 1999, PNR estimates that the assessment phase is
approximately 99% complete on a worldwide basis and has included, among other
procedures, (1) the identification of necessary remediation, upgrade and/or
replacement of existing information technology applications and systems; (2) the
assessment of non-information technology exposures, such as telecommunications
systems, security systems, elevators and process control equipment; (3) the
initiation of inquiry and dialogue with significant third party business
partners, customers and suppliers in an effort to understand and assess their
Year 2000 problems, readiness and potential impact on PNR and its Year 2000
problem; (4) the implementation of processes designed to reduce the risk of
reintroduction of Year 2000 problems into PNR's systems and business processes;
and, (5) the formulation of contingency plans for mission-critical information
technology systems.
The completion of the assessment phase of PNR's Year 2000 project has been
delayed by limited responses received on inquiries made of third party business
partners, customers and suppliers.
5
As of June 30, 1999, PNR estimates that the remedial phase is approximately
83% complete, on a worldwide basis, subject to the continuing results of the
third party inquiry assessments and the testing phase. The remedial phase has
included the upgrade and/or replacement of certain applications and hardware
systems. The remediation of non-information technology is expected to be
completed by October 1999. PNR's Year 2000 remedial actions have not
significantly delayed other information technology projects or upgrades. The
testing phase of PNR's Year 2000 project is expected to be completed by the end
of November 1999. None of PNR's costs related to the Year 2000 are passed
through to the Trust.
A failure to remedy a critical Year 2000 problem could have a materially
adverse effect on PNR's results of operations and financial condition. The most
likely worst case scenario which may be encountered as a result of a Year 2000
problem could include information and non-information system failures, the
receipt or transmission of erroneous data, lost data or a combination of similar
problems of a magnitude to PNR that cannot be accurately assessed at this time.
In the assessment phase of PNR's Year 2000 project, contingency plans were
designed to mitigate the exposure to mission critical information technology
systems, such as oil and gas sales receipts; vendor and royalty cash
distributions; debt compliance; accounting; and, employee compensation. Such
contingency plans anticipate the extensive utilization of third-party data
processing services, personal computer applications and the substitution of
courier and mail services in place of electronic data interchange. Given the
uncertainties regarding the scope of the Year 2000 problem and the compliance of
significant third parties, there can be no assurance that contingency plans will
have anticipated all Year 2000 scenarios.
The Trustee has developed and is implementing a program to prepare its
systems and applications for the Year 2000, including those used to render
services to the Trust. In that connection, the Trustee intends to have such
systems and applications capable of processing, on and after January 1, 2000,
date, and date-related data consistent with the functionality of such systems
and applications, without a material adverse effect upon its performance of
services as Trustee. Third parties that the Trust conducts business with could
be prone to Year 2000 problems that could not be assessed or detected by the
Trust. The Trust is contacting the major third parties to determine whether they
will be able to resolve, in a timely manner, any Year 2000 problems directly
affecting the Trust and to inform them of the Trust's internal assessment of its
Year 2000 review.
Information above with respect to PNR is based upon information provided by
PNR to the Trustee for use in this Form 10-Q.
FINANCIAL REVIEW
During the second quarter of 1999, the Trust had distributable income of
$1,958,849, representing $.0272 per unit, as compared to $324,206, representing
$.0045 per unit in the second quarter of 1998. The per unit amounts of
distributable income for the second quarter of 1999 and 1998 were earned by
month as follows:
1999 1998
--------- ---------
April................................ $ -- $ .0036
May.................................. .0270 .0008
June................................. .0002 .0001
--------- ---------
$ .0272 $ .0045
========= =========
Royalty income increased to $2,288,525 in the second quarter of 1999 as
compared to $440,956 in the second quarter of 1998. The increase in Royalty
income is primarily due to the release of amounts
6
previously withheld by Pioneer relating to potential liabilities for royalty
claims of approximately $3.1 million ($2.1 million net of deficit). See
"Operational Review." However, excluding this one-time payment from Pioneer,
royalty income would have decreased as compared to second quarter 1998. This is
due to substantially lower production volumes on South Marsh Island blocks 155
and 156 and West Delta blocks 61 and 62 and decreased prices for crude oil,
condensate and natural gas liquids in the second quarter of 1999 when compared
to the corresponding 1998 period.
Production volumes for natural gas decreased to 186,466 Mcf in the second
quarter of 1999 from 331,591 Mcf in the second quarter of 1998. The average
price received for natural gas was $1.58 per Mcf in the second quarter of 1999
compared to $2.21 per Mcf in the second quarter of 1998.
Crude oil, condensate and natural gas liquids production decreased to 2,212
barrels in the second quarter of 1999 from 15,357 barrels in the second quarter
of 1998. The average price received for crude oil, condensate and natural gas
liquids was $9.34 per barrel in the second quarter of 1999, compared to $12.84
per barrel in the second quarter of 1998.
The decrease in natural gas and crude oil, condensate and natural gas
liquids production for both the six months and the quarter ended June 30, 1999
when compared to the comparable periods of 1998 are primarily attributable to
natural production declines on South Marsh Island blocks 155 and 156 and West
Delta 61 and 62 blocks.
For the six months ended June 30, 1999, natural gas production volumes
decreased to 462,586 Mcf from 805,665 Mcf for the six months ended June 30,
1998. Crude oil, condensate and natural gas liquids production volumes decreased
to 8,002 barrels in the first six months of 1999 as compared to 24,440 barrels
in the first six months of 1998.
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 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.
PNR has advised the Trust that during the second quarter of 1999 its
offshore gas production was marketed under short term contracts at spot market
prices primarily to H&N, Limited. PNR has further advised the Trust 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
1999 were lower than spot market prices in the second quarter of 1998.
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 OPEC and other
oil and gas producers, weather, industrial growth, conservation measures,
competition and other variables.
7
The Brazos A-39 block experienced a decrease in natural gas production in
the second quarter of 1999 as compared to the second quarter of 1998 primarily
due to natural production decline. The Brazos A-7 block experienced a decrease
in production 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. During the fourth quarter of 1998, PNR incurred $7.35 million ($661,000
net to the Trust) of completion costs for the Brazos A-7 No. 5 well. As of June
30, 1999, the cost carryforward resulting from the completion costs on the
Brazos A-7 No. 5 well, other capital expenditures and over distributions by PNR
were recovered. The No. 5 well commenced production late in the fourth quarter
of 1998 and is currently producing at a rate of approximately 10 MMcf per day.
The South Marsh Island 155 and 156 blocks experienced a decrease in
production in the second quarter of 1999 as compared to the second quarter of
1998, primarily due to the cessation of production from the A-19 well in late
1998 and natural production decline. This block is currently not producing, but
a workover was performed in May 1999 to attempt to restore production. The
workover was not successful and PNR is currently exploring several alternatives
to attempt to restore production. A plan should be completed in the second half
of 1999. 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 and PNR has no current plans for additional drilling.
The West Delta 61 and 62 blocks experienced a decrease in oil and in
natural gas production in the second quarter of 1999 as compared to the second
quarter of 1998 primarily due to the cessation of production of PNR operated
wells. These wells are currently uneconomic to produce. 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 which 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 10% (9% net to the Trust) overriding royalty
interest. A new well was drilled in the third quarter of 1998 which encountered
320 net feet of pay in eight Miocene sands below a true vertical depth of 7,500
feet. In the fourth quarter of 1998, the operator drilled one development well
and one exploratory well. The development well encountered 250 net feet of pay
in seven Miocene sands. The operator has elected to set a four-pile platform,
and production began in the second quarter of 1999. The exploratory well tested
a new fault block which was determined to be non-commercial. The exploratory
well was subsequently plugged in the first quarter of 1999. The Trust will
receive an 11.25% overriding royalty interest in these wells. Division orders
have been signed and the Trust should begin receiving revenues from these new
wells in the third quarter of 1999.
Matagorda Island 624 oil and natural gas production decreased in the second
quarter of 1999 as compared to the second quarter of 1998, primarily due to
natural production decline. Gross producing rate of the block was approximately
1.1 MMcf of gas and 23 barrels of condensate per day as of August 1999.
TERMINATION OF THE TRUST
The terms of the Mesa Offshore Trust Indenture provide 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 or (2)
a vote by the unitholders 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 1998 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
8
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 $128,000, $173,000
and $123,000 for the years 1998, 1997, and 1996, respectively.
The December 31, 1998, reserve report prepared for the Partnership (see the
Trust's 1998 Annual Report on Form 10-K) indicates that 95% of future net
revenues will be received by the Trust during the next four years. As such, it
is possible, depending on the timing of future production, market conditions,
the success of future drilling activities, if any, and other matters, that in
2000 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 2000 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.
9
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, 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
THREE MONTHS ENDED JUNE 30, 1998:
Ninety percent of gross
proceeds....................... $ 255,981 $ 399,775 $ 105,088 $168,446 $ 929,290
Less ninety percent of --
Operating expenditures......... (67,478) (193,294) (178,471) (28,245) (467,488)
Capital costs recovered........ -- -- -- (802) (802)
Accrual for future abandonment
costs and interest on cost
carryforward................ (11,727) (1,500) (5,848) (925) (20,000)
--------- ----------- ---------- ---------- -----------
Net proceeds (excess costs)...... $ 176,776 $ 204,981 $ (79,231) $138,474 $ 441,000
========= =========== ========== ========== ===========
Trust share of net proceeds
(99.99%)....................... $ 440,956
===========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 153 13,758 -- 1,446 15,357
========= =========== ========== ========== ===========
Average sales price per Bbl.... $ 12.11 $ 12.86 $ -- $ 12.77 $ 12.84
========= =========== ========== ========== ===========
Natural gas (Mcf).............. 117,251 98,517 43,814 72,009 331,591
========= =========== ========== ========== ===========
Average sales price per Mcf.... $ 2.17 $ 2.26 $ 2.40 $ 2.08 $ 2.21
========= =========== ========== ========== ===========
Producing wells.................. 3 3 3 1 10
- ------------
o The amounts shown are for Mesa Offshore Royalty Partnership.
o The amounts for the three months ended June 30, 1999 and 1998 represent
actual production for the periods February 1999 through April 1999 and
February 1998 through April 1998, 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.
10
SOUTH
BRAZOS MARSH WEST MATAGORDA
A-7 AND ISLAND 155 DELTA 61 ISLAND
A-39 AND 156 AND 62 624 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
SOUTH
BRAZOS MARSH WEST MATAGORDA
A-7 AND ISLAND 155 DELTA 61 ISLAND
A-39 AND 156 AND 62 624 TOTAL
--------- ---------- ---------- --------- -----------
SIX MONTHS ENDED JUNE 30, 1998:
Ninety percent of gross
proceeds....................... $ 557,803 $ 725,015 $ 455,209 $ 562,188 $ 2,300,215
Less ninety percent of --
Operating expenditures......... (157,378) (507,546) (356,010) (102,011) (1,122,945)
Capital costs recovered........ -- -- -- (1,883) (1,883)
Accrual for future abandonment
costs....................... (23,454) (3,000) (11,696) (1,850) (40,000)
--------- ---------- ---------- --------- -----------
Net proceeds (excess costs)...... $ 376,971 $ 214,469 $ 87,503 $ 456,444 $ 1,135,387
========= ========== ========== ========= ===========
Trust share of net proceeds
(99.99%)....................... $ 1,135,274
===========
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 433 20,252 594 3,161 24,440
========= ========== ========== ========= ===========
Average sales price per Bbl.... $ 13.71 $ 14.17 $ 15.51 $ 14.80 $ 14.28
========= ========== ========== ========= ===========
Natural gas (Mcf).............. 233,776 182,941 172,719 216,229 805,665
========= ========== ========== ========= ===========
Average sales price per Mcf.... $ 2.36 $ 2.39 $ 2.58 $ 2.38 $ 2.42
========= ========== ========== ========= ===========
Producing wells.................. 3 3 3 1 10
- ------------
o The amounts shown are for Mesa Offshore Royalty Partnership.
o The amounts for the six months ended June 30, 1999 and 1998 represent actual
production for the periods November 1998 through April 1999, and November
1997 through April 1998 respectively.
o Gross proceeds for West Delta 61 and 62 for the six 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.
11
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.
12
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: August 10, 1999
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.
13