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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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
OR
[_] 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: 0-6910
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TEL OFFSHORE TRUST
(Exact Name of Registrant as Specified in its Charter)
TEXAS 76-6004064
(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 (Zip Code)
Executive Offices)
Registrant's Telephone Number, Including Area Code: (713) 216-5712
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 6, 1997 -- 4,751,510 Units of Beneficial Interest in TEL
Offshore Trust.
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<PAGE>
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 are forward-looking
statements. Although the Working Interest Owners have advised the Trust that
they believe that the expectations reflected in the forward-looking statements
contained herein 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. 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.
i
<PAGE>
PART I -- FINANCIAL INFORMATION
ITEM 1 -- FINANCIAL STATEMENTS
TEL 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....................... $ 2,051,820 $ 0 $ 3,177,825 $ 0
Interest income...................... 12,507 8,622 23,237 17,309
------------ ------------ ------------ ------------
2,064,327 8,622 3,201,062 17,309
Decrease (increase) in reserve for
future Trust expenses.............. (58,848) 113,821 (356,591) 284,917
General and administrative
expenses........................... (141,152) (122,443) (243,409) (302,226)
------------ ------------ ------------ ------------
Distributable income................. $ 1,864,327 $ 0 $ 2,601,062 $ 0
============ ============ ============ ============
Distributions per Unit (4,751,510
Units)............................. $ .392365 $ 0 $ .547417 $ 0
============ ============ ============ ============
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
JUNE 30, DECEMBER 31,
1997 1996
---------- ------------
(UNAUDITED)
ASSETS
Cash and cash equivalents............ $3,100,541 $ 879,623
Net overriding royalty interest in
producing oil and gas properties,
net of accumulated amortization of
$27,426,281 and
$27,329,066, respectively.......... 841,374 938,589
---------- ------------
Total assets......................... $3,941,915 $1,818,212
========== ============
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit
holders............................ $1,864,327 $ 0
Reserve for future Trust expenses.... 1,236,214 879,623
Commitments and contingencies (Note
7).................................
Trust corpus (4,751,510 Units of
beneficial interest authorized and
outstanding)....................... 841,374 938,589
---------- ------------
Total liabilities and Trust corpus... $3,941,915 $1,818,212
========== ============
The accompanying notes are an integral part of these financial statements.
1
<PAGE>
TEL 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.... $ 911,004 $ 1,071,618 $ 938,589 $ 1,071,618
Distributable income................. 1,864,327 0 2,601,062 0
Distribution payable to Unit
holders............................ (1,864,327) 0 (2,601,062) 0
Amortization of net overriding
royalty interest................... (69,630) 0 (97,215) 0
-------------- ------------ -------------- ------------
Trust corpus, end of period.......... $ 841,374 $ 1,071,618 $ 841,374 $ 1,071,618
============== ============ ============== ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
2
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- TRUST ORGANIZATION
Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL
Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of
Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December
22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership
("Partnership") was formed in which the Trust owns a 99.99% interest and
Tenneco Oil Company ("Tenneco") initially owned a .01% interest. In general,
the Plan was effected by transferring an overriding royalty interest
("Royalty") equivalent to a 25% net profits interest in the oil and gas
properties (the "Royalty Properties") of Tenneco Exploration, Ltd.
("Exploration I") located offshore Louisiana to the Partnership and issuing
certificates evidencing units of beneficial interest in the Trust ("Units") in
liquidation and cancellation of Tenneco Offshore's common stock.
On October 31, 1986, Exploration I was dissolved and the oil and gas
properties of Exploration I were distributed to Tenneco subject to the Royalty.
Tenneco, who was then serving as the Managing General Partner of the
Partnership, assumed the obligations of Exploration I, including its obligations
under the instrument conveying the Royalty to the Partnership (the
"Conveyance"). The dissolution of Exploration I had no impact on future cash
distributions to Unit holders.
On November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired most of
the Gulf of Mexico offshore oil and gas properties of Tenneco, including all the
Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as
the Working Interest Owner and Managing General Partner of the Partnership.
Chevron also assumed Tenneco's obligations under the Conveyance.
On October 30, 1992, Pennzoil Company ("Pennzoil") acquired certain oil
and gas producing properties from Chevron, including four of the Royalty
Properties. The four Royalty Properties acquired by Pennzoil were East Cameron
354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of
such acquisition, Pennzoil replaced Chevron as the Working Interest Owner of
such properties on October 30, 1992. Pennzoil also assumed Chevron's obligations
under the Conveyance with respect to such properties.
On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco")
acquired one of the Royalty Properties from Chevron. The Royalty Property
acquired by Texaco was West Cameron 643. As a result of such acquisition, Texaco
replaced Chevron as the Working Interest Owner of such property on December 1,
1994. Texaco also assumed Chevron's obligations under the Conveyance with
respect to such property.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from Pennzoil. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
Pennzoil. As a result of such acquisitions, SONAT and Amoco have replaced
Pennzoil as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, and also assumed Pennzoil's obligations
under the Conveyance with respect to such properties.
All of the Royalty Properties continue to be subject to the Royalty, and it
is anticipated that the Trust and the Partnership, in general, will continue to
operate as if the above-described sales of the Royalty Properties had not
occurred.
Unless the context in which such terms are used indicates otherwise, in
these Notes the terms "Working Interest Owner" and "Working Interest Owners"
generally refer to the owner or owners of the
3
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TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
Royalty Properties (Exploration I through October 31, 1986; Tenneco for periods
from October 31, 1986 until November 18, 1988; Chevron with respect to all
Royalty Properties for periods from November 18, 1988 until October 30, 1992,
and with respect to all Royalty Properties except East Cameron 354, Eugene
Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30,
1992 until December 1, 1994, and with respect to the same properties except West
Cameron 643 thereafter; Pennzoil with respect to East Cameron 354, Eugene Island
348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992
until October 1, 1995, and with respect to Eugene Island 348 and Eugene Island
208 thereafter; Texaco with respect to West Cameron 643 for periods beginning on
or after December 1, 1994; SONAT with respect to East Cameron 354 for periods
beginning on or after October 1, 1995; and Amoco with respect to Eugene Island
367 for periods beginning on or after October 1, 1995).
NOTE 2 -- BASIS OF ACCOUNTING
The accompanying unaudited financial information has been prepared by Texas
Commerce Bank National Association ("Corporate Trustee") in accordance with
the instructions to Form 10-Q and does not include all of the information
required by generally accepted accounting principles for complete financial
statements, although the Corporate Trustee and the individual trustees
(collectively, the "Trustees") believe that the disclosures are adequate to
make the information presented not misleading. The information furnished
reflects all adjustments which are, in the opinion of the Trustees, 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 Annual Report on Form 10-K
for the year ended December 31, 1996.
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income is recorded when received by the Corporate Trustee
on the last business day of each calendar quarter; and
(b) Trust general and administrative expenses are recorded when paid,
except for the cash reserved for future general and
administrative expenses, as discussed in Note 6.
This manner of reporting income and expenses is considered to be the most
meaningful because the quarterly distributions to Unit holders are based on net
cash receipts received from the Working Interest Owners. The financial
statements of the Trust differ from financial statements prepared in accordance
with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would
be recognized on an accrual basis. In addition, amortization of the overriding
royalty interest, which is calculated based on units-of-production, is charged
directly to Trust corpus since such amount does not affect distributable income.
Cash and cash equivalents include all highly liquid short term investments
with original maturities of three months or less.
NOTE 3 -- OVERRIDING ROYALTY INTEREST
The Royalty entitles the Trust to its share (99.99%) of 25% of the Net
Proceeds attributable to the Royalty Properties. The Conveyance, dated January
1, 1983, provides that the Working Interest Owners will calculate, for each
period of three months commencing the first day of February, May, August and
November, an amount equal to 25% of the Net Proceeds from their oil and gas
properties for the period. Generally, Net Proceeds are the amounts received by
the Working Interest Owners from the sale of minerals
4
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
from the Royalty Properties less operating and capital costs incurred,
management fees and expense reimbursements owing the Managing General Partner of
the Partnership, applicable taxes other than income taxes, and cash escrows.
Cash escrows are for the future costs to be incurred to plug and abandon wells,
dismantle and remove platforms, pipelines and other production facilities, and
for the estimated amount of future capital expenditures on the Royalty
Properties. Net Proceeds do not include amounts received by the Working Interest
Owners as advance gas payments, "take-or-pay" payments or similar payments
unless and until such payments are extinguished or repaid through the future
delivery of gas.
NOTE 4 -- DISTRIBUTIONS TO UNIT HOLDERS
In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. The
amounts distributed are determined on a quarterly basis and are payable to Unit
holders of record as of the last business day of each calendar quarter. However,
cash distributions are made in January, April, July and October and include
interest earned from the quarterly record date to the date of distribution.
NOTE 5 -- SPECIAL COST ESCROW ACCOUNT
The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the Royalty Properties, as well as for the estimated amount of
future drilling projects and other capital expenditures on the Royal Properties.
As provided in the Conveyance, the amount of funds to be reserved is determined
based on factors including estimates of aggregate future production costs,
aggregate future Special Costs, aggregate future net revenues and actual current
net proceeds. Deposits into this account reduce current distributions and are
placed in an escrow account and invested in short-term certificates of deposit.
Such account is herein referred to as the "Special Cost Escrow Account." The
Trust's share of interest generated from the Special Cost Escrow Account serves
to reduce the Trust's share of allocated production costs. Special Cost Escrow
funds will generally be utilized to pay Special Costs to the extent there are
not adequate current net proceeds to pay such costs. Special Costs that have
been paid are no longer included in the Special Cost Escrow calculation.
Deposits to the Special Cost Escrow Account will generally be made when the
balance in the Special Cost Escrow Account is less than 125% of future Special
Costs and there is a Net Revenues Shortfall (a calculation of the excess of
estimated future costs over estimated future net revenues pursuant to a formula
contained in the Conveyance). When there is not a Net Revenues Shortfall,
amounts in the Special Cost Escrow Account will generally be released, to the
extent that Special Costs have been incurred. Amounts in the Special Cost Escrow
Account generally will also be released when the balance in such account exceeds
125% of future Special Costs. In the first six months of 1996, a deposit of
approximately $1,321,000 was made by the Trust into the Special Cost Escrow
Account. The deposit was primarily a result of an increase in the estimates of
projected capital expenditures, production costs and abandonment costs in
connection with the Ship Shoal 182/183 drilling. In the first six months of
1997, there was a net deposit of funds into the Special Cost Escrow Account. The
Trust's share of the funds deposited was approximately $778,000. The deposit was
primarily a result of an increase in the current estimate of projected capital
expenditures, production costs and abandonment costs in connection with the West
Cameron 643 drilling in 1996. As of June 30, 1997, approximately $4,846,000 (net
to the Trust) remained in the Special Cost Escrow Account.
5
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
Chevron, in its capacity as Managing General Partner, has advised the Trust
that additional deposits to the Special Cost Escrow Account may be required in
future periods in connection with other production costs, other abandonment
costs, other capital expenditures and changes in the estimates and factors
described above. Such deposits could result in a significant reduction in
Royalty income in the periods in which such deposits are made, including the
possibility that no Royalty income would be received in such periods.
NOTE 6 -- EXPENSE RESERVE
At December 31, 1991, a cash reserve of $120,000 had been established for
future Trust general and administrative expenses. During 1992 and 1993, in
anticipation of future periods when the cash received from the Royalty may not
be sufficient for payment of Trust expenses, the reserve for future Trust
general and administrative expenses was increased each quarter by an amount
equal to the difference between $150,000 and the amount of the Trust's general
and administrative expenses for such quarter. In March 1994, the Trust
determined, in accordance with the Trust Agreement, to begin further increasing
the Trust's cash reserve each quarter by an amount equal to the difference
between $200,000 and the amount of the Trust's general and administrative
expenses for such quarter. During 1996, the Trust used net cash of $298,309 from
the Trust's cash reserve account to pay the Trust's general and administrative
expenses, due to the absence of Royalty income in the first, second and fourth
quarters. In the first quarter of 1997, the Trust determined to make a special
deposit of $200,000 into the Trust's cash reserve to replenish a portion of the
funds expended in 1996. This $200,000 deposit was made in addition to the
regular quarterly deposit, which for the first quarter of 1997 was $97,743. In
the second quarter of 1997, the general and administrative expenses of the Trust
were approximately $141,200. Accordingly, the Trust's cash reserve was increased
by approximately $58,800 in such quarter, bringing the total amount of the
Trust's cash reserve at June 30, 1997 to $1,236,214.
NOTE 7 -- COMMITMENTS AND CONTINGENCIES
During 1994, Pennzoil, the Working Interest Owner on the Eugene Island 348
property, settled a gas imbalance on that property for approximately $2,696,000.
The Trust's share of this settlement amount was approximately $674,000, of which
approximately $266,300 has been recovered from the Trust by the Working Interest
Owner through the second quarter of 1997, and the remainder will be subject to
recovery from the Trust in future periods, in accordance with the Conveyance.
The Working Interest Owner has advised the Trust that future Royalty income
attributable to all of the Royalty Properties owned by Pennzoil will be used to
offset the Trust's share of such settlement amounts. Based on current
production, prices and expenses for the Royalty Properties owned by Pennzoil, it
is estimated that Royalty income attributable to such properties will be
retained by Pennzoil for the remaining life of the Trust.
The Working Interest Owners have advised the Trust that, although they
believe that they are in general compliance with applicable health, safety and
environmental laws and regulations that have taken effect at the federal, state
and local levels, costs may be incurred to comply with current and proposed
environmental legislation which could result in increased operating expenses on
the Royalty Properties.
6
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL REVIEW
THREE MONTHS ENDED JUNE 30, 1997 AND 1996
Distributions to Unit holders for the three months ended June 30, 1997
amounted to $1,864,327 or $.392365 per Unit as compared to no distribution for
the same period in 1996. The Trust had no Royalty income for the three months
ended June 30, 1996. The increase in distributable income for the second quarter
of 1997 was primarily due to a significant increase in crude oil and condensate
revenues in the second quarter of 1997, as compared to the second quarter of
1996.
Gas revenues increased approximately 57% in the second quarter of 1997
compared to the second quarter of 1996 primarily due to an 89% increase in gas
volumes, which increase was primarily attributable to production from the B-9
well on the West Cameron 643 property. The increase in volumes was offset by a
17% decrease in the average price received for natural gas from $2.70 per Mcf in
the second quarter of 1996 to $2.23 per Mcf in the second quarter of 1997. Crude
oil and condensate revenues increased approximately 183% in the second quarter
of 1997 in comparison to the same period in 1996 primarily due to a 167%
increase in crude oil and condensate volumes from the 1996 second quarter to the
1997 second quarter. This increase was primarily attributable to increased
production from the B-11, B-12 and B-13 wells on the Ship Shoal 182/183
property. In addition, there was a 6% increase in the average price received
from $18.49 per barrel in the second quarter of 1996 to $19.56 per barrel in the
second quarter of 1997. The Trust's share of capital expenditures decreased by
approximately 92% or $423,040 in the second quarter of 1997 as compared to the
same period in 1996 primarily due to expenses incurred on the F-2 well drilled
on the Ship Shoal 182/183 property in the first quarter of 1996.
For the second quarter of 1997, the Trust had undistributed net income of
$49,315. Undistributed net income represents positive Net Proceeds generated
during the period that were applied to an existing loss carryforward. The
undistributed net income for the second quarter of 1997 was applied to a loss
carryforward that resulted primarily from the Eugene Island 348 gas imbalance
settlement in 1994. See Note 7 in the Notes to Financial Statements for
information regarding such settlement.
In the second quarter of 1997, there was a net deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $434,000, compared to a deposit of funds into the Special Cost
Escrow Account of approximately $316,000 net to the Trust in the second
quarter of 1996. The Special Cost Escrow is set aside for estimated abandonment
costs and future capital expenditures as provided for in the Conveyance. For
additional information relating to the Special Cost Escrow see "Special Cost
Escrow Account" below.
SIX MONTHS ENDED JUNE 30, 1997 AND 1996
Distributions to Unit holders for the six months ended June 30, 1997
amounted to $2,601,062 or $.547417 per Unit as compared to no distribution for
the same period in 1996. The Trust had no Royalty income for the six months
ended June 30, 1996. The increase in distributable income for the first six
months of 1997 was primarily due to a significant increase in gas and crude oil
and condensate revenues in the first six months of 1997, as compared to the same
period in 1996.
Gas revenues increased approximately 193% in the first six months of 1997
compared to the first six months of 1996 primarily due to a 162% increase in gas
volumes, which increase was primarily attributable
7
<PAGE>
to production from the B-8 and B-9 wells on the West Cameron 643 property that
were completed in the second quarter of 1996. In addition, there was a 12%
increase in the average price received for natural gas from $2.60 per Mcf in the
first six months of 1996 to $2.91 per Mcf in the first six months of 1997. Crude
oil and condensate revenues increased approximately 101% in the first six months
of 1997 in comparison to the same period in 1996 primarily due to a 56% increase
in crude oil and condensate volumes. This increase was primarily attributable to
production from the B-11, B-12 and B-13 wells on the Ship Shoal 182/183
property. In addition, there was a 29% increase in the average price received
from $16.47 per barrel for the six months ended June 30, 1996 to $21.19 per
barrel for the six months ended June 30, 1997. The Trust's share of capital
expenditures decreased by approximately 15% or $128,384 for the six months ended
June 30, 1997 as compared to the same period in 1996 primarily due to the F-2
well drilled on the Ship Shoal 182/183 property in the first quarter of 1996.
The Trust's share of operating expenses increased approximately 23% or $159,786
for the six months ended June 30, 1997 as compared to the same period in 1996
due primarily to a workover on the E-9 well on the Ship Shoal 182/183 property
in the first quarter of 1997.
For the first six months of 1997, the Trust had undistributed net income of
$892,778. Undistributed net income represents positive Net Proceeds generated
during the period that were applied to an existing loss carryforward. The
undistributed net income for the the first six months of 1997 was applied to a
loss carryforward that resulted primarily from the drilling of the B-11, B-12
and B-13 wells on the Ship Shoal 182/183 property in the first three quarters of
1996.
In the first six months of 1997, there was a net deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $778,000, compared to a deposit of funds into the Special Cost
Escrow Account of $1,321,000 net to the Trust in the first six months of 1996.
For additional information relating to the Special Cost Escrow see "Special
Cost Escrow Account" below.
RESERVE FOR FUTURE TRUST EXPENSES
In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. During
1992 and 1993, in anticipation of future periods when the cash received from the
Royalty may not be sufficient for payment of Trust expenses, the reserve for
future Trust general and administrative expenses was increased each quarter by
an amount equal to the difference between $150,000 and the amount of the Trust's
general and administrative expenses for such quarter. In March 1994, the Trust
determined, in accordance with the Trust Agreement, to begin further increasing
the Trust's cash reserve each quarter by an amount equal to the difference
between $200,000 and the amount of the Trust's general and administrative
expenses for such quarter. During 1996, the Trust used net cash of $298,309 from
the Trust's cash reserve account to pay the Trust's general and administrative
expenses, due to the absence of Royalty income during the first, second and
fourth quarters. After receipt of Royalty income in the first quarter of 1997,
the Trust determined to make a special deposit of $200,000 into the Trust's cash
reserve to replenish a portion of the funds expended in 1996. This $200,000
deposit was made in addition to the regular quarterly deposit, which for the
first quarter of 1997 was $97,743. In the second quarter of 1997, the general
and administrative expenses of the Trust were approximately $141,200.
Accordingly, the Trust's cash reserve was increased by approximately $58,800 in
such quarter, bringing the total amount of the Trust's cash reserve at June 30,
1997 to $1,236,214.
OTHER
The amount of cash distributed by the Trust is dependent on, among other
things, the sales prices and quantities of oil and gas produced from the Royalty
Properties. It should be noted that substantial
8
<PAGE>
uncertainties exist with regard to future oil and gas prices, which are subject
to material fluctuations due to changes in production levels and pricing and
other actions taken by major petroleum producing nations, as well as the
regional supply and demand for oil and gas, weather, industrial growth,
conservation measures, competition and other variables.
OPERATIONAL REVIEW
THREE MONTHS ENDED JUNE 30, 1997 AND 1996
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY
THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 crude oil revenues increased from $970,071 in the second
quarter of 1996 to $6,896,637 in the second quarter of 1997, primarily due to an
increase in crude oil production from 52,023 barrels in the second quarter of
1996 to 342,423 barrels for the same period in 1997. The increase in crude oil
production was due primarily to the successful drilling of the B-11, B-12 and
B-13 wells in the first three quarters of 1996. In addition, there was an
increase in the average crude oil price from $18.65 per barrel in the second
quarter of 1996 to $20.14 per barrel for the same period in 1997. Gas revenues
increased from $220,506 in the second quarter of 1996 to $908,641 in the second
quarter of 1997 primarily due to an increase in gas volumes from 80,014 Mcf in
the second quarter of 1996 to 434,507 Mcf in the second quarter of 1997. The
increase in gas volumes was also primarily due to the successful drilling of the
B-11, B-12 and B-13 wells. The increase in volumes was partially offset by a
decrease in the average natural gas sales price from $2.92 per Mcf in the second
quarter of 1996 to $2.09 per Mcf in the same period of 1997. The majority of the
gas from this property is being purchased by NGC Corp. at spot market index
prices. In addition, the Working Interest Owner has advised the Trust that
approximately 57,197 Mcf have been overtaken by the Working Interest Owner from
this property as of April 30, 1997. The Trust's share of this overtake position
is approximately 14,299 Mcf. Accordingly, gas revenues from this property may be
reduced in future periods while underproduced parties recover their share of the
gas imbalance. Chevron has advised the Trust that it believes sufficient gas
reserves exist on Ship Shoal 182/183 for underproduced parties to recoup their
share of the gas imbalance on this property. Capital expenditures decreased from
$1,307,815 in the second quarter of 1996 to ($81,848) for the same period in
1997 due to the drilling of the F-2 well on this property in the first quarter
of 1996 and a $220,000 credit for casings returned for the B-12 well in the
second quarter of 1997. Operating expenses increased slightly from $492,815 in
the second quarter of 1996 to $493,348 for the same period in 1997. The Working
Interest Owner has advised the Trust that it began drilling the B-15 development
gas well on this property in June 1997 at an approximate cost of $2.5 million
($625,000 net to the Trust).
Eugene Island 339 crude oil revenues decreased from $1,943,120 in the
second quarter of 1996 to $1,304,829 in the second quarter of 1997 due primarily
to a decrease in volumes from 105,534 barrels in the second quarter of 1996 to
76,970 barrels in the second quarter of 1997. The decrease in volumes was
primarily attributable to a continued natural production decline on this
property. In addition, there was a decrease in the average crude oil price from
$18.41 per barrel in the second quarter of 1996 to $16.95 per barrel in the
second quarter of 1997. Gas revenues decreased from $454,921 in the second
quarter of 1996 to $137,527 in the second quarter of 1997 due to a decrease in
gas volumes from 148,975 Mcf in the second quarter of 1996 to 62,668 Mcf for the
same period in 1997. The decrease in gas volumes was due primarily to a well
being shut down during the second quarter of 1997 for compressor repair. In
addition, there was a decrease in the average price received for natural gas
from $3.02 per Mcf in the second quarter of 1996 to $2.21 per Mcf in the second
quarter of 1997. The Working Interest Owner has advised the Trust that there is
an overtake imbalance position of approximately 227,992 Mcf on this property as
of April 30, 1997. The Trust's share of this overtake position is approximately
56,998 Mcf. Accordingly, gas revenues from this
9
<PAGE>
property may be reduced in future periods while underproduced parties recoup
their share of the gas imbalance. Chevron has advised the Trust that it believes
sufficient gas reserves exist on the Eugene Island 339 for underproduced parties
to recoup their share of the gas imbalance on this property. The gas from this
property is currently committed to NGC Corp. pursuant to an agreement providing
for gas to be purchased at the spot market index prices. Operating expenses
increased from $324,399 in the second quarter of 1996 to $590,672 for the same
period in 1997 due primarily to service facility charges in the second quarter
of 1997. The Working Interest Owner has advised the Trust that it plans to drill
the B-7 and B-18 sidetrack wells in late 1997 at an aggregate cost of
approximately $2.5 million ($625,000 net to the Trust).
West Cameron 643 gas revenues increased from $1,608,803 in the second
quarter of 1996 to $2,351,044 in the second quarter of 1997 due primarily to an
increase in gas volumes from 620,259 Mcf in the second quarter of 1996 to
1,053,600 Mcf for the same period in 1997. The increase in gas volumes was due
primarily to the successful B-8 and B-9 wells drilled on this property in the
second quarter of 1996 and the successful workovers on the A-2 and A-9 wells in
the first quarter of 1996. The increase in volumes was slightly offset by a
decrease in the average price received for natural gas from $2.59 per Mcf in the
second quarter of 1996 to $2.23 per Mcf for the same period of 1997. The Working
Interest Owner has advised the Trust that the gas from this property is
currently committed to Tennessee Gas and Columbia Gas Pipeline Company pursuant
to an agreement for gas to be purchased at a calculated monthly price based on
the spot market rate. Capital expenditures decreased from $521,959 in the second
quarter of 1996 to ($31,736) in the second quarter of 1997 due primarily to
costs associated with workovers on the A-2 and A-9 wells on this property in the
first quarter of 1996 and a credit for returned equipment in the second quarter
of 1997. Operating expenses decreased from $531,952 in the second quarter of
1996 to $339,791 in the second quarter of 1997 due primarily to costs associated
with the workovers described above.
In March 1997, Chevron advised the Trust that Texaco had drilled two
exploratory wells on East Cameron 371 at a cost of approximately $1,437,175
($359,294 net to the Trust). No well tests have been performed to date and none
are planned until construction of the platform is complete. The estimated date
of completion for the platform is the first quarter of 1998. In addition, Texaco
has advised the Trust that it intends to pursue additional drilling on this
property. The estimated total cost of the drilling and platform construction is
approximately $5.9 million ($1.5 million net to the Trust).
SIX MONTHS ENDED JUNE 30, 1997 AND 1996
Volumes and dollar amounts discussed below represent amounts recorded by
the Working Interest Owners unless otherwise specified.
Ship Shoal 182/183 crude oil revenues increased from $1,871,528 in the
first six months of 1996 to $12,569,251 in the first six months of 1997,
primarily due to an increase in crude oil production from 107,996 barrels in the
first six months of 1996 to 580,713 barrels for the same period in 1997. The
increase in crude oil production was due primarily to the successful drilling of
the B-11, B-12 and B-13 wells in the first three quarters of 1996. In addition,
there was an increase in the average crude oil price from $17.33 per barrel in
the first six months of 1996 to $21.64 per barrel for the same period in 1997.
Gas revenues increased from $452,833 in the first six months of 1996 to
$2,259,299 in the first six months of 1997 primarily due to an increase in gas
volumes from 165,437 Mcf in the first six months of 1996 to 812,010 Mcf in the
first six months of 1997. The increase in gas volumes was also primarily due to
the successful drilling of the B-11, B-12 and B-13 wells. The increase in
volumes was slightly offset by a decrease in the average natural gas sales price
from $2.84 per Mcf in the first six months of 1996 to $2.82 per Mcf in the same
period of 1997. Capital expenditures increased from $1,974,279 in the first six
months of 1996 to $2,170,816 in the first six months of 1997 due to the drilling
and completion of the B-11, B-12 and B-13 wells. Operating expenses increased
from $790,594 in the first six months of 1996 to $1,235,952 for the same period
in 1997 due primarily to a workover on the E-9 well in the first quarter of
1997.
10
<PAGE>
Eugene Island 339 crude oil revenues decreased from $5,910,665 in the first
six months of 1996 to $3,028,695 in the first six months of 1997 due primarily
to a decrease in volumes from 364,522 barrels in the first six months of 1996 to
155,227 barrels in the first six months of 1997. The decrease in volumes was
primarily attributable to an adjustment on the B-13 well in the first quarter of
1996. This decrease in production was partially offset by an increase in the
average crude oil price from $16.21 per barrel in the first six months of 1996
to $19.51 per barrel in the first six months of 1997. Gas revenues decreased
from $805,359 in the first six months of 1996 to $513,948 in the first six
months of 1997 due to a decrease in gas volumes from 294,744 Mcf in the first
six months of 1996 to 175,368 Mcf for the same period in 1997. The decrease in
gas volumes was due primarily to a well being shut down during the first and
second quarter of 1997 for upgrading the facility and compressor repair. The
decrease in gas volumes was slightly offset by an increase in the average price
received for natural gas from $2.73 per Mcf in the first six months of 1996 to
$2.98 per Mcf in the first six weeks of 1997. Operating expenses increased from
$614,672 in the first six months of 1996 to $1,031,519 for the first six months
in 1997 due primarily to service facility credits on this property in the first
quarter of 1996 and service facility charges in the second quarter of 1997.
West Cameron 643 gas revenues increased from $2,041,628 in the first six
months of 1996 to $6,931,646 in the first six months of 1997 due primarily to an
increase in gas volumes from 803,814 Mcf in the first six months of 1996 to
2,364,726 Mcf for the same period in 1997. The increase in gas volumes was due
primarily to the successful B-8 and B-9 wells drilled on this property in the
second quarter of 1996 and the successful workovers in the A-2 and A-9 wells in
the first quarter of 1996. In addition, there was an increase in the average
price received for natural gas from $2.54 per Mcf in the first six months of
1996 to $2.93 per Mcf for the same period in 1997. Capital expenditures
decreased from $1,298,362 in the first six months of 1996 to $367,659 in the
first six months of 1997 due primarily to costs associated with workovers on the
A-2 and A-9 wells on this property in the first quarter of 1996. Operating
expenses decreased from $962,801 in the first six months of 1996 to $880,220 in
the first six months of 1997 due primarily to costs associated with the
workovers described above.
FUTURE NET REVENUES AND TERMINATION OF THE TRUST
Based on a reserve study provided to the Trust by DeGolyer and MacNaughton,
independent petroleum engineers, it was estimated that as of October 31, 1996
future net revenues attributable to the Trust's royalty interests approximated
$30.9 million. Such reserve study also indicates that approximately 81% of the
future net revenues from the Royalty Properties are expected to be received by
the Trust during the next 4 years. In addition, because the Trust will terminate
in the event estimated future net revenues fall below $2 million, it would be
possible for the Trust to terminate even though some or all of the Royalty
Properties continued to have remaining productive lives. Upon termination of the
Trust, the Trustees will sell for cash all of the assets held in the Trust
estate and make a final distribution to Unit holders of any funds remaining
after all Trust liabilities have been satisfied. The estimates of future net
revenues discussed above are subject to large variances from year to year and
should not be construed as exact. There are numerous uncertainties present in
estimating future net revenues for the Royalty Properties. The estimate may vary
depending on changes in market prices for crude oil and natural gas, the
recoverable reserves, annual production and costs assumed by DeGolyer and
MacNaughton. In addition, future economic and operating conditions as well as
results of future drilling plans may cause significant changes in such estimate.
The discussion set forth above is qualified in its entirety by reference to the
Trust's 1996 Annual Report on Form 10-K. The Form 10-K is available upon request
from the Corporate Trustee.
SPECIAL COST ESCROW ACCOUNT
The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the Royalty Properties, as well as
11
<PAGE>
for the estimated amount of future drilling projects and other capital
expenditures on the Royalty Properties. As provided in the Conveyance, the
amount of funds to be reserved is determined based on factors including
estimates of aggregate future production costs, aggregate future Special Costs,
aggregate future net revenues and actual current net proceeds. Deposits into
this account reduce current distributions and are placed in an escrow account
and invested in short-term certificates of deposit. Such account is herein
referred to as the "Special Cost Escrow Account." The Trust's share of interest
generated from the Special Cost Escrow Account serves to reduce the Trust's
share of allocated production costs. Special Cost Escrow funds will generally be
utilized to pay Special Costs to the extent there are not adequate current net
proceeds to pay such costs. Special Costs that have been paid are no longer
included in the Special Cost Escrow calculation. Deposits to the Special Cost
Escrow Account will generally be made when the balance in the Special Cost
Escrow Account is less than 125% of future Special Costs and there is a Net
Revenues Shortfall (a calculation of the excess of estimated future costs over
estimated future net revenues pursuant to a formula contained in the
Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special
Cost Escrow Account will generally be released, to the extent that Special Costs
have been incurred. Amounts in the Special Cost Escrow Account generally will
also be released when the balance in such account exceeds 125% of future Special
Costs. In the first six months of 1996, a deposit of approximately $1,321,000
was made by the Trust into the Special Cost Escrow Account. The deposit was
primarily a result of an increase in the estimates of projected capital
expenditures, production costs and abandonment costs in connection with the Ship
Shoal 182/183 drilling. In the first six months of 1997, there was a net deposit
of funds into the Special Cost Escrow Account. The Trust's share of the funds
deposited was approximately $778,000. The deposit was primarily a result of an
increase in the current estimates of projected capital expenditures, production
costs and abandonment costs in connection with the West Cameron 643 drilling in
1996. As of June 30, 1997, approximately $4,846,000 (net to the Trust) remained
in the Special Cost Escrow Account.
Chevron, in its capacity as Managing General Partner, has advised the Trust
that additional deposits to the Special Cost Escrow Account may be required in
future periods in connection with other production costs, other abandonment
costs, other capital expenditures and changes in the estimates and factors
described above. Such deposits, if made, could result in a significant reduction
in Royalty income in the periods in which such deposits are made, including the
possibility that no Royalty income would be received in such periods.
OVERVIEW OF PRODUCTION, PRICES AND NET PROCEEDS
The following schedule provides a summary of the volumes and weighted
average prices for crude oil and condensate and natural gas recorded by the
Working Interest Owners for the Royalty Properties, as well as the Working
Interest Owners' calculations of the net proceeds and the royalties paid to the
Trust during the periods indicated. Net proceeds due to the Trust are calculated
for each three month period commencing on the first day of February, May, August
and November.
12
<PAGE>
ROYALTY PROPERTIES
THREE MONTHS ENDED
JUNE 30,(1)
------------------------------
1997 1996
-------------- --------------
Crude oil and condensate (bbls)......... 422,338 158,077
Natural gas and gas products (Mcf)...... 1,699,755 897,287
Crude oil and condensate average price,
per bbl............................... $ 19.56 $ 18.49
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.23 $ 2.70
Crude oil and condensate revenues....... $ 8,259,693 $ 2,922,715
Natural gas and gas products revenues... 3,784,703 2,417,520
Production expenses..................... (1,757,162) (1,752,252)
Capital expenditures.................... (149,727) (1,841,888)
Undistributed Net Loss (Income)(2)...... (193,615) (483,963)
(Provision for) Refund of escrowed
special costs......................... (1,735,792) (1,262,132)
-------------- --------------
NET PROCEEDS............................ 8,208,100 0
Royalty interest........................ x25% x25%
-------------- --------------
Partnership share....................... 2,052,025 0
Trust interest.......................... x99.99% x99.99%
-------------- --------------
Trust share............................. $ 2,051,820 $ 0
============== ==============
- ------------
(1) The amounts for the three months ended June 30, 1997 and 1996 represent
actual production for the periods February 1996 through April 1997 and
February 1995 through April 1996, respectively.
(2) Undistributed net loss represents negative Net Proceeds generated during the
respective period. An undistributed net loss is carried forward and offset,
in future periods, by positive Net Proceeds earned by the related Working
Interest Owner(s). Undistributed net income represents positive Net
Proceeds, generated during the respective period, that were applied to an
existing loss carryforward. As of June 30, 1997, the loss carryforward was
$1,923,984 ($480,996 net to the Trust).
13
<PAGE>
ROYALTY PROPERTIES
SIX MONTHS ENDED JUNE 30,(1)
------------------------------
1997 1996
-------------- --------------
Crude oil and condensate (bbls)......... 740,422 474,075
Natural gas and gas products (Mcf)...... 3,648,437 1,390,059
Crude oil and condensate average price,
per bbl............................... $ 21.19 $ 16.47
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.91 $ 2.60
Crude oil and condensate revenues....... $ 15,692,677 $ 7,808,076
Natural gas and gas products revenues... 10,560,234 3,607,889
Production expenses..................... (4,012,986) (3,064,492)
Capital expenditures.................... (2,844,526) (3,358,061)
Undistributed Net Loss (Income)(2)...... (3,571,111) 292,568
(Provision for) Refund of escrowed
special costs......................... (3,111,716) (5,285,980)
-------------- --------------
NET PROCEEDS............................ 12,712,572 0
Royalty interest........................ x25% x25%
-------------- --------------
Partnership share....................... 3,178,143 0
Trust interest.......................... x99.99% x99.99%
-------------- --------------
Trust share............................. $ 3,177,825 $ 0
============== ==============
- ------------
(1) 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.
(2) Undistributed net loss represents negative Net Proceeds generated during the
respective period. An undistributed net loss is carried forward and offset,
in future periods, by positive Net Proceeds earned by the related Working
Interest Owner(s). Undistributed net income represents positive Net
Proceeds, generated during the respective period, that were applied to an
existing loss carryforward. As of June 30, 1997, the loss carryforward was
$1,923,984 ($480,996 net to the Trust).
14
<PAGE>
PART II -- OTHER INFORMATION
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
------------- -------
<S> <C> <C> <C>
4(a)* -- Trust Agreement dated as of January 1, 1983, among Tenneco
Offshore Company, Inc., Texas Commerce Bank National
Association, as corporate trustee, and Horace C. Bailey, Joseph
C. Broadus and F. Arnold Daum, as individual trustees (Exhibit
4(a) to Form 10-K for the year ended December 31, 1992 of TEL
Offshore Trust)................................................ 0-6910 4(a)
4(b)* -- Agreement of General Partnership of TEL Offshore Trust
Partnership between Tenneco Oil Company and the TEL Offshore
Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for
year ended December 31, 1992 of TEL Offshore Trust)............ 0-6910 4(b)
4(c)* -- Conveyance of Overriding Royalty Interests from Exploration I
to the Partnership (Exhibit 4(c) to Form 10-K for year ended
December 31, 1992 of TEL Offshore Trust)....................... 0-6910 4(c)
4(d)* -- Amendments to TEL Offshore Trust Trust Agreement, dated
December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended
December 31, 1992 of TEL Offshore Trust)....................... 0-6910 4(d)
4(e)* -- Amendment to the Agreement of General Partnership of TEL
Offshore Trust Partnership, effective as of January 1, 1983
(Exhibit 4(e) to Form 10-K for year ended December 31, 1992 of
TEL Offshore Trust)............................................ 0-6910 4(e)
10(a)* -- Purchase Agreement, dated as of December 7, 1984 by and between
Tenneco Oil Company and Tenneco Offshore II Company (Exhibit
10(a) to Form 10-K for year ended December 31, 1992, of TEL
Offshore Trust)................................................ 0-6910 10(a)
10(b)* -- Consent Agreement, dated November 16, 1988, between TEL
Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form
10-K for year ended December 31, 1988 of TEL Offshore Trust)... 0-6910 10(b)
10(c)* -- Assignment and Assumption Agreement, dated November 17, 1988,
between Tenneco Oil Company and TOC-Gulf of Mexico Inc.
(Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of
TEL Offshore Trust)............................................ 0-6910 10(c)
10(d)* -- Gas Purchase and Sales Agreement Effective September 1, 1993
between Tennessee Gas Pipeline Company and Chevron U.S.A.
Production Company (Exhibit 10(d) to Form 10-K for year ended
December 31, 1993 of TEL Offshore Trust)....................... 0-6910 10(d)
27(a) -- Financial Data Schedule
</TABLE>
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange
Commission during the second quarter of 1997.
15
<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.
TEL OFFSHORE TRUST
By: Texas Commerce Bank National
Association, Corporate Trustee
By: /s/ PETE FOSTER
PETE FOSTER
SENIOR VICE PRESIDENT
AND TRUST OFFICER
Date: August 12, 1997
The Registrant, TEL 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.
16
<PAGE>
TEL
OFFSHORE
TRUST
FEDERAL INCOME TAX
INFORMATION
1997
<PAGE>
TEL OFFSHORE TRUST
EIN 76-6004064
SCHEDULE B
SECOND QUARTER 1997
TAX INFORMATION PER UNIT
(4,751,510 UNITS)
<TABLE>
<CAPTION>
PARTNERSHIP
ITEMS PER UNIT TRUST ITEMS PER UNIT
----------------------------- -------------------------------------------
DEPLETION **(INCREASE)
ROYALTY AS A PERCENT INTEREST ADMINISTRATIVE DECREASE
RECORD DATE INCOME OF ROYALTY BASIS INCOME EXPENSE IN RESERVE
- ---------------------------------------- ---------- ---------------- ---------- -------------- ------------
<S> <C> <C> <C> <C> <C>
March 31, 1997.......................... 0.236978 3.6440% 0.002258 0.021521 (0.062663)
June 30, 1997........................... 0.431825 6.6402% 0.002632 0.029707 (0.012385)
September 30, 1997...................... 0.000000 0.0000% 0.000000 0.000000 (0.000000)
December 31, 1997....................... 0.000000 0.0000% 0.000000 0.000000 0.000000
---------- ---------------- ---------- -------------- ------------
Year to date............................ 0.668803 10.2842% 0.004890 0.051228 (0.075048)
========== ================ ========== ============== ============
</TABLE>
SUMMARY OF TAXABLE INCOME
PER UNIT
---------
Royalty Income.......................... 0.668803
Interest Income......................... 0.004890
Depletion Deduction..................... (0.022101)
Administrative Expense Deduction........ (0.051228)
(Increase)/Decrease in Reserve.......... (0.075048)
---------
Net Amount.............................. 0.525316
=========
<PAGE>
TAX BASIS OF UNITS AND ROYALTY*
Basis Assigned to TEL Offshore Trust Units -- 1/1/83 ............. $ 6.750000
Basis Allocated to Offshore II Company (Sold December 17, 1984) .. (0.120000)
----------
Royalty Basis 1/1/83 ............................................. 6.630000
Depletion Year 1983 .............................................. (0.769366)
----------
Royalty Basis 1/1/84 ............................................. 5.860634
Depletion Year 1984 .............................................. (1.203489)
----------
Royalty Basis 1/1/85 ............................................. 4.657145
Depletion Year 1985 .............................................. (1.126563)
----------
Royalty Basis 1/1/86 ............................................. 3.530582
Depletion Year 1986 .............................................. (0.555675)
----------
Royalty Basis 1/1/87 ............................................. 2.974907
Depletion Year 1987 .............................................. (1.424231)
----------
Royalty Basis 1/1/88 ............................................. 1.550676
Depletion Year 1988 .............................................. (0.384321)
----------
Royalty Basis 1/1/89 ............................................. 1.166355
Depletion Year 1989 .............................................. (0.241515)
----------
Royalty Basis 1/1/90 ............................................. 0.924840
Depletion Year 1990 .............................................. (0.242097)
----------
Royalty Basis 1/1/91 ............................................. 0.682743
Depletion Year 1991 .............................................. (0.092228)
----------
Royalty Basis 1/1/92 ............................................. 0.590515
Depletion Year 1992 .............................................. (0.058181)
----------
Royalty Basis 1/1/93 ............................................. 0.532334
Depletion Year 1993 .............................................. (0.079729)
----------
Royalty Basis 1/1/94 ............................................. 0.452605
Depletion Year 1994 .............................................. (0.148288)
----------
Royalty Basis 1/1/95 ............................................. 0.304317
Depletion Year 1995 .............................................. (0.064972)
----------
Royalty Basis 1/1/96 ............................................. 0.239345
Depletion Year 1996 .............................................. (0.024448)
----------
Royalty Basis 1-1-97 ............................................. 0.214897
Depletion Through 2nd Quarter 1997 ............................... (0.022101)
----------
Royalty Basis 6/30/97 ............................................ 0.192796
==========
- ------------
* For Unit holders who acquired their Units in the initial distribution in
January of 1983.
For Unit holders acquiring Units other than in the initial distribution from
Tenneco Offshore Company and prior to December 17, 1984, their royalty basis
should be equal to 98.2533% of the purchase price of such Units, less
depletion taken from the date of purchase.
Unit holders who acquired their Units after December 17, 1984 will have a
basis in the royalty equal to the purchase price of such Units, less
depletion taken from the date of purchase.
** Increase or decrease in the reserve amount has no tax effect and is shown for
information purposes only.
<PAGE>
TEL OFFSHORE TRUST
P.O. BOX 4717
HOUSTON, TEXAS 77210
TEL OFFSHORE TRUST
1997
SECOND QUARTER REPORT TO
UNIT HOLDERS
QUARTER ENDED JUNE 30, 1997
ATTENTION UNIT HOLDERS
Texas Commerce Bank as Trustee for TEL Offshore Trust has established the
following toll free information line for unit holder inquiries: 1-800-852-1422
and an Internet news source may be accessed at:
WWW.BUSINESSWIRE.COM/CNN/TEL-OFFSHORE.HTM
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS AS OF JUNE 30, 1997 AND THE
STATEMENT OF DISTRIBUTABLE INCOME FOR THE SIX MONTHS ENDED JUNE 30, 1997 AND
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1997
<CASH> 3,100,541
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3,100,541
<PP&E> 28,267,655
<DEPRECIATION> 27,426,281
<TOTAL-ASSETS> 3,941,915
<CURRENT-LIABILITIES> 1,864,327
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 841,374
<TOTAL-LIABILITY-AND-EQUITY> 3,941,915
<SALES> 0
<TOTAL-REVENUES> 3,201,062
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 600,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 2,601,062
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,601,062
<EPS-PRIMARY> 0.547
<EPS-DILUTED> 0.547
</TABLE>
