================================================================================
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, 1997
[_] 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.)
TEXAS COMMERCE BANK
NATIONAL ASSOCIATION
CORPORATE TRUST DIVISION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(713) 216-6369
(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, 1997 -- 71,980,216 Units of Beneficial Interest in Mesa
Offshore Trust.
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<PAGE>
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
1997 1996 1997 1996
------------ ---------- ------------ ----------
<S> <C> <C> <C> <C>
Royalty income....................... $ 1,786,585 $ -- $ 2,898,140 $ 36,014
Interest income...................... 35,801 16,961 53,413 32,750
General and administrative expense... (30,432) (16,961) (650,066) (68,764)
------------ ---------- ------------ ----------
Distributable income............ $ 1,791,954 $ -- $ 2,301,487 $ --
============ ========== ============ ==========
Distributable income per unit... $ .0248 $ -- $ .0319 $ --
============ ========== ============ ==========
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
JUNE 30, DECEMBER 31,
1997 1996
------------- -------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 3,756,153 $ 1,535,247
Interest receivable.................. 35,801 5,090
Net overriding royalty interest in
oil and gas properties............. 380,905,000 380,905,000
Accumulated amortization............. (379,987,998) (379,842,595)
------------- -------------
4,708,956 $ 2,602,742
============= =============
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses........... $ 2,000,000 $ 1,540,337
Distributions payable................ 1,791,954 --
Trust corpus (71,980,216 units of
beneficial interest
authorized and outstanding)........ 917,002 1,062,405
------------- -------------
4,708,956 $ 2,602,742
============= =============
(The accompanying notes are an integral part of these financial statements.)
1
<PAGE>
MESA OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- ----------------------------
1997 1996 1997 1996
------------ ------------ ------------ --------------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period.... $ 1,006,629 $ 1,062,405 $ 1,062,405 $ 1,067,160
Distributable income................. 1,791,954 -- 2,301,487 --
Distributions to unitholders......... (1,791,954) -- (2,301,487) --
Amortization of net overriding
royalty interest................... (89,627) -- (145,403) (4,755)
------------ ------------ ------------ --------------
Trust corpus, end of period.......... $ 917,002 $ 1,062,405 $ 917,002 $ 1,062,405
============ ============ ============ ==============
</TABLE>
(The accompanying notes are an integral part of these financial statements.)
2
<PAGE>
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- TRUST ORGANIZATION
The Mesa Offshore Trust (the "Trust") was created effective December 1,
1982 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 and the managing general partner of the Royalty
properties. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural
Resources Company ("Pioneer") and Parker & Parsley Petroleum Company merged with
and into Pioneer Natural Resources USA, Inc. (formerly 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.
STATUS OF THE TRUST
PNR completed the drilling on Matagorda Island block 624 in 1995 and it
drilled five wells from the existing "A" platform on the South Marsh Island 155
block during 1996. PNR recovered substantially all remaining costs related to
the South Marsh Island drilling program as of the February 1997 reporting month.
In addition, the Trust recovered approximately $.6 million in administrative
expenses paid from the Trust's reserve fund during the period in which Royalty
income was not paid to the Trust, replenishing the Trust's expense reserve fund
balance to $2 million.
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 recovery of costs associated with the
Matagorda Island 624 and South Marsh Island drilling programs caused the cash
received by the Trust in 1996 to fall below the termination threshold prescribed
in the Indenture. However, based on the overall success of the South Marsh
Island drilling program, payments of Royalty income to the Trust have resumed as
of the April 30, 1997 payable date and the cash it has received in 1997 is above
the termination threshold prescribed in the Trust Indenture.
Furthermore, the December 31, 1996, reserve report prepared for the
Partnership (see the Trust's 1996 Annual Report on Form 10-K) indicates that 85%
of future net revenues will be received by the Trust during the next two years.
As such, it is possible, depending on market conditions and the success of
future drilling activities, if any, that as early as 1999 the Trust may commence
a period of three successive years in which annual net royalty income would be
below the termination threshold prescribed in the Indenture, resulting in
termination of the Trust pursuant to the terms discussed above.
NOTE 2 -- BASIS OF PRESENTATION
The accompanying unaudited financial information has been prepared by Texas
Commerce Bank 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
3
<PAGE>
should be read in conjunction with the financial statements and notes thereto
included in the Trust's 1996 Annual Report on Form 10-K.
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income recorded for a month is the Trust's interest in
the amount computed and paid by 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 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.
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 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 be calculated
only for the periods 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.
4
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-Q, including without
limitation the statements under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 1 to the financial
statements of the Trust regarding the future net revenues of the Trust, are
forward-looking statements. Although MESA Inc. and Pioneer (subsequent to the
Merger) 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, and in the Trust's Form 10-K
including without limitation in conjunction with the forward-looking statements
included in this Form 10-Q. 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 1997, the Trust had distributable income of
$1,791,954, representing $.0248 per unit, as compared to no distributable income
in the second quarter of 1996. The resumption of distributions is due to the
recovery as of the February 1997 reporting month of substantially all remaining
costs related to the drilling on South Marsh Island and Matagorda Island
discussed below. The per unit amounts of distributable income for the second
quarter of 1997 and 1996 were earned by month as follows:
1997 1996
--------- ---------
April................................ $ .0122 $ --
May.................................. .0080 --
June................................. .0046 --
--------- ---------
$ .0248 $ --
========= =========
Royalty income increased to $1,786,585 in the second quarter of 1997 as
compared to no royalty income for the first quarter of 1996. The increase in
Royalty income is due to the recovery of drilling costs by PNR on the South
Marsh Island blocks 155 and 156 and increased prices for natural gas in 1997.
Production volumes for natural gas increased to 1,057,041 Mcf in the second
quarter of 1997 from 726,904 Mcf in the second quarter of 1996. The average
price received for natural gas was $1.99 per Mcf in the second quarter of 1997
compared to $2.65 per mcf in the second quarter of 1996.
Crude oil, condensate and natural gas liquids production inreased to 45,707
barrels in the second quarter of 1997 from 24,097 barrels in the second quarter
of 1996. The average price received for crude oil, condensate and natural gas
liquids was $14.91 per barrel in the second quarter of 1997, compared to $13.68
per barrel in the second quarter of 1996.
The increase in natural gas and crude oil, condensate and natural gas
liquids production in the second quarter of 1997 when compared to the second
quarter of 1996 is primarily attributable to new production on South Marsh
Island, partially offset by natural production decline on West Delta.
For the six months ended June 30, 1997, natural gas production volumes
increased to 2,692,893 Mcf from 1,490,275 Mcf for the six months ended June 30,
1996. Crude oil, condensate and natural gas liquids production volumes increased
to 106,405 barrels in the first six months of 1997 as compared to 42,906
5
<PAGE>
barrels in the first six months of 1996. The increase in natural gas production
and crude oil, condensate and natural gas liquids production was primarily due
to new production on South Marsh Island.
OPERATIONAL REVIEW
PNR has advised the Trust that during the second quarter of 1997 its
offshore gas production was marketed under short term contracts at spot market
prices to multiple purchasers, including Penn Union Energy, Energy Source, Inc.
and Conoco, 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 1997 were lower higher than spot market prices in the
second quarter of 1996.
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, storage levels, industrial growth, conservation
measures, competition and other variables.
The Brazos A-7 and A-39 blocks experienced an increase in production in the
second quarter of 1997 as compared to the second quarter of 1996 primarily due
to the resumption of production from block A-39, well A-3. Well A-3 resumed
operation in September 1996 and is producing approximately 3 MMcf of gas per day
as of July 1997. PNR has farmed out a portion of Brazos A-7 to another operator,
and has participated at a 10% working interest in the completion of an
exploratory gas well that was drilled in the second quarter of 1997. The No. 5
well encountered gas pay and is temporarily abandoned. A completion proposal is
expected to be received in the third quarter of 1997. Production from this well
is expected to begin early next year. The completion cost of the No. 5 well to
date approximately is $700,000 ($63,000 net to the Trust).
The South Marsh Island 155 and 156 blocks experienced an increase in
production in the second quarter of 1997 as compared to 1996, primarily due to
new production from the A-20, A-21, A-6 sidetrack, A-22 and A-14 sidetrack wells
which were drilled in the first three quarters of 1996. The initial gross
producing rate of these five wells was approximately 40 MMcf of gas and 1,000
barrels of condensate per day which rate has subsequently declined to
approximately 8 MMcf of gas and 300 barrels of condensate per day as of July
1997. The decrease in production is primarily due to natural production decline.
A recompletion of the A-6 sidetrack well in the second quarter of 1997 was
performed at a cost of approximately $30,000 ($19,000 net to the Trust). The
initial production after recompletion was 10 MMcf of gas per day which rate
declined to 1.5 MMcf of gas per day as of July 1997 due to continuation of the
natural production decline. PNR has purchased 3-D seismic for approximately
$300,000 gross ($189,000 net to the Trust) to evaluate future drilling potential
on the South Marsh Island 156 block.
The West Delta 61 and 62 blocks experienced a decrease in oil and in
natural gas production in the second quarter of 1997 as compared to the second
quarter of 1996 primarily due to natural production decline. 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. PNR is currently evaluating
additional drilling opportunities for this property in areas not subject to the
farmout agreement.
Matagorda Island 624 oil and natural gas production increased in the second
quarter of 1997 as compared to the second quarter of 1996, primarily due to
improved performance in the A-1 well. The A-8 development well, which was
drilled in the fourth quarter of 1995, is currently shut in due to mechanical
problems. A tubing replacement is planned for the last half of 1997 at an
estimated cost of $376,600 ($110,000 net to the Trust). Gross producing rate of
the block was approximately 4 MMcf of gas and 90 barrels of condensate per day
as of July 1997.
6
<PAGE>
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 1996 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, $123,000, $149,000 and
$177,500 for the years 1996, 1995, and 1994, respectively. Royalty income of
$2,898,140 as of June 30, 1997 was above the termination threshold prescribed in
the Indenture.
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. The discussion set
forth above is qualified in its entirety by reference to the Partnership
Agreement itself, which is available upon request from the Trustee.
On August 7, 1997, MESA Inc. and Parker & Parsley Petroleum Company merged
to create Pioneer Natural Resources Company, the third largest independent oil
and gas exploration and production company in the United States. Pioneer has
advised the Trust that this merger should have no significant effects on the
Trust, although the precise nature of any effects cannot be predicted or
quantified at this time.
7
<PAGE>
The following tables provide a summary of the calculations of the net
proceeds attributable to the Partnership's royalty interest (unaudited):
<TABLE>
<CAPTION>
SOUTH
BRAZOS MARSH WEST
A-7 AND ISLAND 155 DELTA 61 MATAGORDA
A-39 AND 156 AND 62 ISLAND 624 TOTAL
---------- ------------ ----------- ---------- ------------
<S> <C> <C> <C> <C> <C>
THREE MONTHS ENDED JUNE 30, 1997:
Ninety percent of gross
proceeds....................... $ 357,122 $ 1,817,894 $ 296,225 $309,604 $ 2,780,845
Less ninety percent of --
Operating expenditures......... (91,808) (407,236) (216,251) (63,503) (778,798)
Capital costs recovered........ -- (173,808) -- (4,564) (178,372)
Accrual for future abandonment
costs....................... (25,074) (1,599) (8,645) (1,593) (36,911)
---------- ------------ ----------- ---------- ------------
Net proceeds..................... $ 240,240 $ 1,235,251 $ 71,329 $239,944 $ 1,786,764
========== ============ =========== ========== ============
Trust share of net proceeds
(99.99%)....................... 1,786,585
============
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 274 40,527 1,051 3,855 45,707
========== ============ =========== ========== ============
Average sales price per Bbl.... $ 17.85 $ 14.35 $ 17.24 $ 19.98 $ 14.91
========== ============ =========== ========== ============
Natural gas (Mcf).............. 177,383 627,343 142,638 109,677 1,057,041
========== ============ =========== ========== ============
Average sales price per Mcf.... $ 1.99 $ 1.97 $ 1.95 $ 2.12 $ 1.99
========== ============ =========== ========== ============
Producing wells.................. 3 5 4 2 14
THREE MONTHS ENDED JUNE 30, 1996:
Ninety percent of gross
proceeds....................... $ 127,272 $ 1,021,101 $ 891,936 $214,513 $ 2,254,822
Less ninety percent of --
Operating expenditures......... (143,946) (221,259) (174,302) (95,059) (634,566)
Capital costs recovered........ -- (1,518,260) -- (20,319) (1,538,579)
Accrual for future abandonment
costs and interest on cost
carryforward................ (9,518) 4,470 (76,551) (78) (81,677)
---------- ------------ ----------- ---------- ------------
Net proceeds (excess costs)...... $ (26,192) $ (713,948) $ 641,083 $ 99,057 $ --
========== ============ =========== ========== ============
Trust share of net proceeds
(99.99%)....................... $ --
============
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... (365) 21,525 1,395 1,542 24,097
========== ============ =========== ========== ============
Average sales price per Bbl.... $ -- $ 14.63 $ 17.00 $ 20.30 $ 13.68
========== ============ =========== ========== ============
Natural gas (Mcf).............. 83,786 236,592 317,637 88,889 726,904
========== ============ =========== ========== ============
Average sales price per Mcf.... $ 2.00 $ 2.98 $ 2.73 $ 2.06 $ 2.65
========== ============ =========== ========== ============
Producing wells.................. 2 4 2 3 11
</TABLE>
- ------------
o The amounts shown are for Mesa Offshore Royalty Partnership.
o The amounts for the three months ended June 30, 1997 and 1996 represent
actual production for the periods February 1997 through April 1997 and
February 1996 through April 1996, respectively.
o Capital costs recovered represents capital costs incurred during the
current or prior periods to the extent that such costs have been recovered
by PNR from current period Gross Proceeds.
o Producing wells indicate the number of wells capable of production as of
the end of the period.
o Crude oil, condensate and natural gas liquids production and prices for
the three months ended June 30, 1996 are distorted due to prior period
accounting adjustments on Brazos A-7 and A-39.
o The cost carryforward resulting from the drilling on South Marsh Island
155/156 was $2,242,370 at June 30, 1996.
8
<PAGE>
<TABLE>
<CAPTION>
SOUTH
BRAZOS MARSH WEST MATAGORDA
A-7 AND ISLAND 155 DELTA 61 ISLAND
A-39 AND 156 AND 62 624 TOTAL
--------- ---------- ----------- --------- ------------
<S> <C> <C> <C> <C> <C>
SIX MONTHS ENDED JUNE 30, 1997:
Ninety percent of gross
proceeds....................... $1,042,580 $6,721,943 $ 982,972 $ 782,018 $ 9,529,513
Less ninety percent of --
Operating expenditures......... (208,538) (731,787) (411,572) (137,629) (1,489,526)
Capital costs recovered........ -- (4,948,156) (33,897) (4,564) (4,986,617)
Accrual for future abandonment
costs........................ (85,116) (18,738) (42,513) (8,573) (154,940)
--------- ---------- ----------- --------- ------------
Net proceeds..................... $ 748,926 $1,023,262 $ 494,990 $ 631,252 $ 2,898,430
========= ========== =========== ========= ============
Trust share of net proceeds
(99.99%)....................... $ 2,898,140
============
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 551 98,090 2,504 5,259 106,404
========= ========== =========== ========= ============
Average sales price per Bbl.... $ 19.88 $ 17.92 $ 19.02 $ 20.82 $ 18.10
========= ========== =========== ========= ============
Natural gas (Mcf).............. 383,203 1,735,686 338,177 235,828 2,692,894
========= ========== =========== ========= ============
Average sales price per Mcf.... $ 2.69 $ 2.86 $ 2.77 $ 2.85 $ 2.82
========= ========== =========== ========= ============
Producing wells.................. 3 5 4 2 14
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, 1996:
Ninety percent of gross
proceeds....................... $ 520,829 $ 1,594,777 $ 1,733,837 $ 435,700 $ 4,285,143
Less ninety percent of --
Operating expenditures......... (298,249) (385,332) (332,252) (188,309) (1,204,142)
Capital costs recovered........ 0 (2,579,981) 0 (314,761) (2,894,742)
Accrual for future abandonment
costs and interest on cost
carryforward................ (38,287) 7,387 (117,011) (2,330) (150,241)
--------- ----------- ----------- --------- ------------
Net proceeds (excess costs)...... $ 184,293 $(1,363,149) $ 1,284,574 $ (69,700) $ 36,018
========= =========== =========== ========= ============
Trust share of net proceeds
(99.99%)....................... $ 36,014
============
Production Volumes and Average
Prices:
Crude oil, condensate and
natural gas liquids
(Bbls)...................... 18 36,478 3,336 3,074 42,906
========= =========== =========== ========= ============
Average sales price per Bbl.... $ -- $ 15.13 $ 15.94 $ 19.35 $ 14.70
========= =========== =========== ========= ============
Natural gas (Mcf).............. 276,952 378,572 646,826 187,925 1,490,275
========= =========== =========== ========= ============
Average sales price per Mcf.... $ 2.00 $ 2.75 $ 2.60 $ 2.00 $ 2.45
========= =========== =========== ========= ============
Producing wells.................. 2 4 2 3 11
</TABLE>
- ------------
o The amounts shown are for Mesa Offshore Royalty Partnership.
o The amounts for the six months ended June 30, 1997 and 1996 represent
actual production for the periods November 1996 through April 1997, and
November 1995 through April 1996 respectively.
o Capital costs recovered represents capital costs incurred during the
current or prior periods to the extent that such costs have been recovered
by PNR from current period Gross Proceeds.
o Producing wells indicate the number of wells capable of production as of
the end of the period.
o Crude oil, condensate and natural gas liquids production and prices for
the six months ended June 30, 1996 are distorted due to prior period
accounting adjustments on Brazos A-7 and A-39.
o The cost carryforward resulting from the drilling on South Marsh Island
155/156 was $2,242,370 at June 30, 1996.
9
<PAGE>
PART II
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.)
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
<C> <S> <C> <C>
4(a) *Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas
Commerce Bank National Association, as Trustee, dated December 15,
1982.................................................................... 2-79673 10(gg)
4(b) *Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa
Offshore Royalty Partnership, dated December 15, 1982................... 2-79673 10(hh)
4(c) *Partnership Agreement between Mesa Offshore Management Co. and Texas
Commerce Bank National Association, as Trustee, dated December 15,
1982.................................................................... 2-79673 10(ii)
4(d) *Amendment to Partnership Agreement between Mesa Offshore Management Co.,
Texas Commerce Bank National Association, as Trustee, and Mesa Operating
Limited Partnership, dated December 27, 1985 (Exhibit 4(d) to Form 10-K
for year ended December 31, 1992 of Mesa Offshore Trust)................ 1-8432 4(d)
4(e) *Amendment to Partnership Agreement between Texas Commerce Bank National
Association, as Trustee and Mesa Operating dated as of January 5, 1994
(Exhibit 4(e) to Form 10-K for year ended December 31, 1993 of Mesa
Offshore Trust)......................................................... 1-8432 4(e)
27 Financial Data Schedule
</TABLE>
(B) REPORTS ON FORM 8-K
None.
10
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THE
REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE
UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
MESA OFFSHORE TRUST
TEXAS COMMERCE BANK
By NATIONAL ASSOCIATION
TRUSTEE
By /s/ PETE FOSTER
PETE FOSTER
SENIOR VICE PRESIDENT & TRUST
OFFICER
Date: August 13, 1997
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
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE MESA
OFFSHORE TRUST 1997 SECOND QUARTER REPORT AND FORM 10-Q AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH 1997 SECOND QUARTER REPORT AND FORM 10-Q.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1997
<CASH> 0
<SECURITIES> 3,756,153
<RECEIVABLES> 35,801
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3,791,954
<PP&E> 380,905,000
<DEPRECIATION> 379,987,998
<TOTAL-ASSETS> 4,708,956
<CURRENT-LIABILITIES> 1,791,954
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 2,917,002
<TOTAL-LIABILITY-AND-EQUITY> 4,708,956
<SALES> 2,898,140
<TOTAL-REVENUES> 2,951,553
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 650,066
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 2,301,487
<INCOME-TAX> 0
<INCOME-CONTINUING> 2,301,487
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,301,487
<EPS-PRIMARY> .032
<EPS-DILUTED> .032
</TABLE>
