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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q/A
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 May 7, 1997 -- 4,751,510 Units of Beneficial Interest in TEL Offshore
Trust.
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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.
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PART I -- FINANCIAL INFORMATION
ITEM 1 -- FINANCIAL STATEMENTS
TEL OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
-------------------------
1997 1996
----------- -----------
Royalty income ..................................... $ 1,126,005 $ 0
Interest income .................................... 10,730 8,687
----------- -----------
1,136,735 8,687
Decrease (increase) in reserve for
future Trust expenses ............................ (297,743) 171,096
General and administrative expenses ................ (102,257) (179,783)
----------- -----------
Distributable income ............................... $ 736,735 $ 0
=========== ===========
Distributions per Unit (4,751,510 Units) ........... $ .155052 $ 0
=========== ===========
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
MARCH 31, DECEMBER 31,
1997 1996
----------- -----------
(UNAUDITED)
ASSETS
Cash and cash equivalents ............................ $ 1,914,101 $ 879,623
Net overriding royalty interest in producing oil
and gas properties, net of accumulated
amortization of $27,356,651 and
$27,329,066, respectively .......................... 911,004 938,589
----------- -----------
Total assets ......................................... $ 2,825,105 $ 1,818,212
=========== ===========
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders ................. $ 736,735 $ 0
Reserve for future Trust expenses .................... 1,177,366 879,623
Commitments and contingencies (Note 7) ...............
Trust corpus (4,751,510 Units of beneficial
interest authorized and outstanding) ............... 911,004 938,589
----------- -----------
Total liabilities and Trust corpus ................... $ 2,825,105 $ 1,818,212
=========== ===========
The accompanying notes are an integral part of these financial statements.
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TEL OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
THREE MONTHS ENDED MARCH 31,
---------------------------
1997 1996
------------ ------------
Trust corpus, beginning of period ................. $ 938,589 $ 1,071,618
Distributable income .............................. 736,735 0
Distribution payable to Unit holders .............. (736,735) 0
Amortization of net overriding royalty interest ... (27,585) 0
------------ ------------
Trust corpus, end of period ....................... $ 911,004 $ 1,071,618
============ ============
The accompanying notes are an integral part of these financial statements.
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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
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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 quarter of 1996, a deposit of
approximately $982,600 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 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 $344,000. The deposit was
primarily a result of an increase in the current estimate of projected capital
expenditures, production costs and abandonment costs of the Royalty Properties.
As of March 31, 1997, approximately $4,412,000 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
5
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TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
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 approximately $400,000
from the Trust's cash reserve account to pay the Trust's general and
administrative expenses for the first, second and fourth quarters, when no
royalty income was received by the Trust. 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. As a result of the regular and special
deposits in the first quarter of 1997, the total amount of the Trust's cash
reserve at March 31, 1997 was $1,177,366.
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 $217,000 has been recovered from the Trust by the Working Interest
Owner through the first 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 Trust does not
anticipate that retention of such Royalty income by Pennzoil will have a
material effect on the Trust's Royalty income as a whole.
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
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL REVIEW
THREE MONTHS ENDED MARCH 31, 1997 AND 1996
Distributions to Unit holders for the three months ended March 31, 1997
amounted to $736,735 or $.155052 per Unit as compared to no distribution for the
same period in 1996. The Trust had no Royalty income for the three months ended
March 31, 1996. The increase in distributable income for the first quarter of
1997 was primarily due to a significant increase in natural gas revenues in the
first quarter of 1997, as compared to the first quarter of 1996.
Gas revenues increased approximately 469% in the first quarter of 1997
compared to the first quarter of 1996 primarily due to a 295% increase in gas
volumes, which was primarily attributable to production from the B-8 and B-9
wells on the West Cameron 643 property. In addition, there was a 44% increase in
the average price received for natural gas from $2.43 per Mcf in the first
quarter of 1996 to $3.50 per Mcf in the first quarter of 1997. Crude oil and
condensate revenues increased approximately 52% in the first quarter of 1997 in
comparison to the same period in 1996 primarily due to a 51% increase in the
average price received from $15.46 per barrel in the first quarter of 1996 to
$23.37 per barrel in the first quarter of 1997. In addition, there was a slight
increase in crude oil and condensate volumes from the 1996 first quarter to the
1997 first quarter. The Trust's share of capital expenditures increased by
approximately 78% or $294,660 in the first quarter of 1997 as compared to the
same period in 1996 primarily due to expenses incurred on the B-11, B-12 and
B-13 wells drilled on the Ship Shoal 182/183 property in the second and third
quarters of 1996. The Trust's share of operating expenses increased by
approximately 61% or $178,490 in the first quarter of 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 quarter of 1997, the Trust had undistributed net income of
$844,374. 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 first quarter of 1997 was primarily related to
a loss carryforward associated with 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. As
of March 31, 1997, the loss carryforward was $2,117,584 ($529,396 net to the
Trust). This remaining loss carryforward relates primarily to 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 first 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 $344,000, compared to a deposit of funds into the Special Cost
Escrow Account of $982,600 net to the Trust in the first 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.
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
7
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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. As a result of the regular and special
deposits in the first quarter of 1997, the total amount of the Trust's cash
reserve at March 31, 1997 was $1,177,366.
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 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 MARCH 31, 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 $901,457 in the first
quarter of 1996 to $5,672,614 in the first quarter of 1997, primarily due to an
increase in crude oil production from 55,973 barrels in the first quarter of
1996 to 238,290 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 $16.11 per barrel to $23.81 per
barrel for the same period in 1997. Gas revenues increased from $232,327 in the
first quarter of 1996 to $1,350,658 in the first quarter of 1997 primarily due
to an increase in gas volumes from 85,423 Mcf in the first quarter of 1996 to
377,503 Mcf in the first 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. In
addition, there was an increase in the average natural gas sales price from
$2.77 per Mcf in the first quarter of 1996 to $3.64 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 30,953 Mcf have been overtaken by the
Working Interest Owner from this property as of January 31, 1997. The Trust's
share of this overtake position is approximately 7,738 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 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 increased from $666,464 in the first quarter of 1996 to $2,252,664
for the same period in 1997 due to the drilling and completing of the B-11, B-12
and B-13 wells. Operating expenses increased from $297,779 in the first quarter
of 1996 to $742,604 for the same period in 1997 due to a workover on the E-9
well in the first quarter of 1997. The Working Interest Owner has advised the
Trust that it plans to drill 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).
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Eugene Island 339 crude oil revenues decreased from $3,967,545 in the first
quarter of 1996 to $1,723,866 in the first quarter of 1997 due primarily to a
decrease in volumes from 258,988 barrels in the first quarter of 1996 to 78,257
barrels in the first quarter 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 $15.32 per barrel in the first quarter of 1996 to $22.03
per barrel in the first quarter of 1997. Gas revenues increased from $350,438 in
the first quarter of 1996 to $376,421 in the first quarter of 1997 due to an
increase in the average price received for natural gas from $2.41 per Mcf in the
first quarter of 1996 to $3.50 per Mcf in the first quarter of 1997. The
increase in average price for natural gas was partially offset by a decrease in
gas volumes from 145,769 Mcf in the first quarter of 1996 to 112,700 Mcf for the
same period in 1997. The decrease in gas volumes was due primarily to a well
being shut down during the first quarter of 1997 for upgrading the facility and
compressor repair. The Working Interest Owner has advised the Trust that there
is an overtake imbalance position of approximately 240,583 Mcf on this property
as of January 31, 1997. The Trust's share of this overtake position is
approximately 60,146 Mcf. Accordingly, gas revenues from this property may be
reduced in future periods while underproduced parties recoup their share of the
gas imbalance. Chevron has advised the Trust that 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
$290,273 in the first quarter of 1996 to $440,847 for the same period in 1997
due primarily to a service facilities credit on this property in the first
quarter of 1996 of approximately $55,000. The Working Interest Owner has advised
the Trust that it plans to drill the B-2, B-4 and B-7 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 $432,825 in the first quarter
of 1996 to $4,580,602 in the first quarter of 1997 due primarily to an increase
in gas volumes from 183,555 Mcf in the first quarter of 1996 to 1,311,126 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 successful workovers on 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 $2.36 per Mcf in the first quarter of 1996 to $3.49 per Mcf in
the first quarter 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 $776,403 in the first quarter of 1996 to $399,395 in the first
quarter of 1997 due primarily to costs associated with workovers on the A-2,
A-6, A-9, A-10, A-16 and B-3 wells on this property in the first quarter of
1996. Operating expenses increased from $430,849 in the first quarter of 1996 to
$540,429 in the first quarter of 1997 due primarily to the repair of a solar
compressor in the first quarter of 1997.
In March 1997, Chevron advised the Trust that Texaco had drilled two
exploratory wells on the East Cameron 371 property 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).
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
9
<PAGE>
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 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 quarter of 1996,
a deposit of approximately $982,600 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 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 $344,000. The deposit
was primarily a result of an increase in the current estimates of projected
capital expenditures, production costs and abandonment costs of the Royalty
Properties. As of March 31, 1997, approximately $4,412,000 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.
10
<PAGE>
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.
ROYALTY PROPERTIES
THREE MONTHS ENDED
MARCH 31,(1)
-----------------------------
1997 1996
------------ ------------
Crude oil and condensate (bbls) .............. 318,084 315,998
Natural gas and gas products (Mcf) ........... 1,948,682 492,772
Crude oil and condensate average price,
per bbl .................................... $ 23.37 $ 15.46
Natural gas average price, per Mcf
(excluding gas products) ................... $ 3.50 $ 2.43
Crude oil and condensate revenues ............ $ 7,432,984 $ 4,885,361
Natural gas and gas products revenues ........ 6,775,531 1,190,369
Production expenses .......................... (2,255,824) (1,312,240)
Capital expenditures ......................... (2,694,799) (1,516,173)
Undistributed Net Loss (Income)(2) ........... (3,377,496) 776,531
(Provision for) Refund of escrowed
special costs .............................. (1,375,924) (4,023,848)
------------ ------------
NET PROCEEDS ................................. 4,504,472 0
Royalty interest ............................. x25% x25%
------------ ------------
Partnership share ............................ 1,126,118 0
Trust interest ............................... x99.99% x99.99%
------------ ------------
Trust share .................................. $ 1,126,005 $ 0
============ ============
- ------------
(1) The amounts for the three months ended March 31, 1997 and 1996 represent
actual production for the periods November 1996 through January 1997 and
November 1995 through January 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 March 31, 1997, the loss carryforward was
$2,117,584 ($529,396 net to the Trust).
11
<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 first quarter of 1997.
12
<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: May 13, 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.
13
<PAGE>
EXHIBIT INDEX
(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>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS AS OF MAR-31-1997 AND THE
STATEMENT OF DISTRIBUTABLE INCOME FOR THE THREE MONTHS ENDED MAR-31-1997 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> MAR-31-1997
<CASH> 1,914,101
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,914,101
<PP&E> 28,267,655
<DEPRECIATION> 27,356,651
<TOTAL-ASSETS> 2,825,105
<CURRENT-LIABILITIES> 736,735
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 911,004
<TOTAL-LIABILITY-AND-EQUITY> 2,825,105
<SALES> 0
<TOTAL-REVENUES> 1,136,735
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 400,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 736,735
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 736,735
<EPS-PRIMARY> .155
<EPS-DILUTED> .155
</TABLE>
