SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1996
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _______TO_______
COMMISSION FILE NO. 0-6910
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)
(713) 216-5712
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS) AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS. [X] YES [ ] 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 6, 1996 -- 4,751,510 UNITS OF BENEFICIAL INTEREST IN TEL
OFFSHORE TRUST.
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,
1996 1995
---------------------
Royalty income........................................... $ 0 $ 262,469
Interest income.......................................... 8,687 6,150
--------- ----------
8,687 268,619
Decrease (increase) in reserve for future Trust expenses. 171,096 (80,564)
General and administrative expenses...................... (179,783) (119,436)
--------- ----------
Distributable income..................................... $ 0 $ 68,619
========= ==========
Distributions per Unit (4,751,510 Units)................. $ 0 $ .014441
========= ==========
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
March 31, 1996 December 31, 1995
-------------- ---------------
(Unaudited)
ASSETS
<S> <C> <C>
Cash and cash equivalents............................................ $ 1,006,836 $ 1,261,606
Net overriding royalty interest in oil and gas properties,
net of accumulated amortization of $27,196,037 and
$27,196,037, respectively........................................ 1,071,618 1,071,618
-------------- ---------------
Total assets......................................................... $ 2,078,454 $ 2,333,224
============== ===============
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders................................. $ 0 $ 83,674
Reserve for future Trust expenses.................................... 1,006,836 1,177,932
Commitments and contingencies (Note 6)...............................
Trust corpus (4,751,510 Units of beneficial interest
authorized and outstanding)...................................... 1,071,618 1,071,618
-------------- ---------------
Total liabilities and Trust corpus................................... $ 2,078,454 $ 2,333,224
============== ===============
</TABLE>
The accompanying notes are an integral part of these financial statements.
-1-
TEL OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
THREE MONTHS ENDED MARCH 31,
1996 1995
------------------------
Trust corpus, beginning of period.................... $1,071,618 $1,343,475
Distributable income................................. 0 68,619
Distribution payable to Unit holders................. 0 (68,619)
Amortization of net overriding royalty interest...... 0 (39,679)
---------- ----------
Trust corpus, end of period.......................... $1,071,618 $1,303,796
========== ==========
The accompanying notes are an integral part of these financial statements.
-2-
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 have assumed Pennzoil's
obligations under the Conveyance with respect to such properties.
Chevron remains the Managing General Partner of the Partnership. All of
the Royalty Properties continue to be subject to the Royalty, and the Trust and
the Partnership, in general, 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 Royalty Properties (Exploration
-3-
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, 1995.
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 5.
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 and current
royalty income in relation to estimated future royalty income, 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.
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 is
effective for financial statements for fiscal years beginning after December 15,
1995. SFAS No. 121 is not anticipated to have a material impact on the financial
position or distributable income of the Trust.
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
-4-
by the Working Interest Owners from the sale of minerals 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 - 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. General and administrative expenses of the Trust were
approximately $179,800 in the first quarter of 1996. In this quarter, the Trust
had no royalty income and interest income of approximately $8,700; therefore,
the Trust's cash reserve was decreased by approximately $171,100 to pay these
expenses, bringing the total amount of the Trust's cash reserve at March 31,
1996 to $1,006,836.
NOTE 6 - 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 $160,200 has been recovered from the Trust by
the Working Interest Owner through the first quarter of 1996, 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.
-5-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FINANCIAL REVIEW
THREE MONTHS ENDED MARCH 31, 1996 AND 1995
The Trust had no royalty income for the three months ended March 31,
1996; therefore, no distribution was made. Distributions to Unit holders for the
three months ended March 31, 1995 amounted to $68,619 or $.014441 per Unit. The
lack of royalty income for the first quarter of 1996 was due primarily to a
larger deposit of funds into the Special Cost Escrow Account (discussed below)
in the first quarter of 1996, as compared to the first quarter of 1995.
Gas revenues increased approximately 27% in the first quarter of 1996
as compared to the first quarter of 1995 primarily due to an increase in the
average price received for natural gas from $1.81 per Mcf in the first quarter
of 1995 to $2.43 per Mcf in the first quarter of 1996. This increase in the
average price was slightly offset by a 3% decrease in gas volumes, which was
primarily attributable to the revised volume allocation on Eugene Island 339 in
the first quarter of 1995 and the continued natural production decline as the
Royalty Properties approach the end of their productive lives. Crude oil
revenues increased approximately 200% in the first quarter of 1996 in comparison
to the same period in 1995 due primarily to a 201% increase in crude oil and
condensate volumes from the 1995 first quarter to the 1996 first quarter. The
increase in crude oil and condensate volumes was slightly offset by a decrease
in the average price received from $15.50 per barrel in the first quarter of
1995 to $15.46 per barrel in the first quarter of 1996. This increase in volumes
and decrease in the average price received was primarily attributable to a well
adjustment on the Eugene Island 339 property in the first quarter of 1996. The
Trust's share of capital expenditures increased by approximately $373,800 in the
first quarter of 1996 in comparison to the first quarter of 1995 primarily due
to six workovers on the West Cameron 643 property and to drilling and completing
a well on the Ship Shoal 182/183 property in the first quarter of 1996. In the
first quarter of 1996, there was an undistributed net loss of approximately
$776,531 compared to undistributed net income of approximately $46,481 in the
first quarter of 1995. The undistributed net loss in the first quarter of 1996
was due primarily to six workovers on the West Cameron 643 property.
In the first quarter of 1996, there was a deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $982,600. During the first quarter of 1995, there was a net
deposit of funds into the Special Cost Escrow Account, the Trust's share of
which was $59,300. 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
page 8 of this Form 10-Q.)
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. General and administrative expenses of
the Trust were approximately $179,800 in the first quarter of 1996. In this
quarter, the Trust had no royalty income and interest income of approximately
$8,700; therefore, the Trust's cash reserve was decreased by approximately
$171,100 to pay these expenses, bringing the total amount of the Trust's cash
reserve at March 31, 1996 to $1,006,836.
-6-
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, 1996 AND 1995
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED
BY THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 crude oil revenues decreased from $1,120,193 in the
first quarter of 1995 to $901,457 in the first quarter of 1996 due primarily to
a 21% decrease in crude oil production. Crude oil production decreased from
70,740 barrels in the first quarter of 1995 to 55,973 barrels in the first
quarter of 1996 primarily due to a continued natural production decline. This
decrease in production was partially offset by an increase in the average crude
oil price from $15.84 per barrel in the first quarter of 1995 to $16.11 per
barrel for the same period in 1996. Gas revenues increased from $201,889 in the
first quarter of 1995 to $232,327 in the first quarter of 1996, primarily due to
an increase in the average natural gas sales price from $1.74 per Mcf in the
first quarter of 1995 to $2.77 per Mcf in the same period of 1996. The increase
in the average natural gas sales price was partially offset by a decrease in gas
volumes. Gas volumes decreased from 114,806 Mcf in the first quarter of 1995 to
85,423 Mcf in the first quarter of 1996 due primarily to the C-4 well being
sanded in during the first quarter of 1996 and the continued natural production
decline. The majority of the gas from this property is being purchased by
Tennessee Gas Pipeline Company ("Tennessee Gas") at a calculated monthly price
based on the spot market rate. In addition, the Working Interest Owner has
advised the Trust that approximately 61,400 Mcf have been overtaken by the
Working Interest Owner from this property as of January 31, 1996. The Trust's
share of this overtake position is approximately 15,350 Mcf. Accordingly, gas
revenues from this property may be reduced in future periods while underproduced
parties recover their share of the gas imbalance. Capital expenditures increased
from $35,604 in the first quarter of 1995 to $666,464 for the same period in
1996 due primarily to the drilling and completing of the F-2 delineation gas
well on this property in the first quarter of 1996. The completed well cost is
estimated at approximately $2.0 million ($492,000 net to the Trust). The Working
Interest Owner advised the Trust that in late March 1996, the F-2 well was
producing approximately 150 Mcf per day. The well is currently shut in for
repairs. In addition, the Working Interest Owner has advised the Trust that it
plans to drill two development oil wells on this property in May 1996 at an
estimated cost of $7.6 million ($1.9 million net to the Trust).
Eugene Island 339 crude oil revenues increased from $473,754 in the
first quarter of 1995 to $3,967,545 in the first quarter of 1996 due to a
significant increase in volumes from 32,057 barrels in the first quarter of 1995
to 258,988 barrels in the first quarter of 1996. This increase in volumes was
primarily attributable to a one-time well adjustment on the B-13 well of 187,000
barrels on this property in the first quarter of 1996. In addition, the average
price received for crude oil and condensate increased from $14.78 per barrel in
the first quarter of 1995 to $15.32 per barrel in the first quarter of 1996. Gas
revenues decreased from $410,751 in the first quarter of 1995 to $350,438 in the
first quarter of 1996 due to a decrease in gas volumes from 206,750 Mcf in the
first quarter of 1995 to 145,769 Mcf for the same period in 1996. The decrease
in gas volumes was due primarily to a revised volume allocation (increased
volume allocated to the Working Interest Owner) of approximately 45,300 Mcf
(11,325 Mcf net to the Trust) on this property in the first quarter of 1995 and
the continued natural production decline. The decrease in volumes was partially
offset by an increase in the average price received for natural gas from $1.93
per Mcf in the first quarter of 1995 to $2.41 per Mcf in the first quarter of
1996. The Working Interest Owner has advised the Trust that there is an overtake
imbalance position of approximately 276,700 Mcf on this property as of January
31, 1996. The Trust's share of this overtake position is approximately 69,175
Mcf. Accordingly, gas revenues from this property may be reduced in future
periods
-7-
while underproduced parties recoup their share of the gas imbalance. The gas
from this property is currently committed to Tennessee Gas pursuant to an
agreement providing for gas to be purchased at a calculated monthly price based
on the spot market rate. Operating expenses decreased from $433,362 in the first
quarter of 1995 to $290,273 for the same period in 1996 due primarily to a
service facilities credit on this property in the first quarter of 1996 of
approximately $55,000. In 1994, the Working Interest Owner purchased a three
dimensional seismic survey of this property. The Working Interest Owner has
advised the Trust that they will pursue drilling on this property in 1997 if
drilling on non-Trust properties in 1996 is successful.
West Cameron 643 gas revenues increased 71% from $253,482 in the first
quarter of 1995 to $432,825 in the first quarter of 1996 due primarily to an
increase in the average price received for natural gas from $1.78 per Mcf in the
first quarter of 1995 to $2.36 per Mcf for the same period in 1996. In addition,
there was an increase in gas volumes from 142,591 Mcf in the first quarter of
1995 to 183,555 Mcf in the first quarter of 1996 due primarily to two successful
workovers on the A-2 and A-9 wells in the first quarter of 1996. Capital
expenditures increased from $241,691 in the first quarter of 1995 to $1,061,593
in the first quarter of 1996 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. The Working Interest Owner has advised the Trust that the
estimated cost yet to be expensed on these workovers is approximately $650,000
($162,500 net to the Trust). Also, the Working Interest Owner has advised the
Trust that in the second quarter of 1996 three wells were drilled on this
property at an aggregate cost of $5.7 million ($1.4 million net to the Trust.)
The Working Interest Owner has advised the Trust that as a result of this
drilling, its estimates of proved reserves on this property have increased by
approximately 12,000 barrels of crude oil and condensate (3,000 barrels net to
the Trust) and 9,600,000 Mcf of gas (2,400,000 Mcf net to the Trust). In
addition, the Working Interest Owner has advised the Trust that it plans to
drill an exploratory well on this property in the third quarter of 1996 at an
estimated cost of approximately $584,000 ($146,000 net to the Trust.) The
Working Interest Owner has advised the Trust that future income from production
on these new wells may be offset significantly by accrued expenses and Special
Cost Escrow deposits related to such wells.
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, 1995 future net revenues attributable to the Trust's royalty
interests approximated $7.5 million. Such reserve study also indicates that
approximately 70% 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 1995 Annual Report on Form 10-K. The Form
10-K is available upon request from the Corporate Trustee.
SPECIAL COST ESCROW
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
-8-
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 1995, a net deposit of
approximately $59,300 was made by the Trust into the Special Cost Escrow
Account. The deposit was primarily a result of an increase in the estimate of
projected capital expenditures on the Royalty Properties. In the first quarter
of 1996, there was a deposit of funds into the Special Cost Escrow Account. The
Trust's share of the funds deposited was approximately $982,600. 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 Ship
Shoal 182/183 drilling. As of March 31, 1996, approximately $3,577,000 remained
in the Special Cost Escrow Account.
Chevron has advised the Trust that the projected capital expenditures,
production costs and abandonment costs in connection with the Ship Shoal 182/183
drilling could result in additional deposits to the Special Cost Escrow Account
for subsequent quarters in 1996. 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.
-9-
ROYALTY PROPERTIES
THREE MONTHS ENDED
MARCH 31, (1)
1996 1995
-------------- ------------
Crude oil and condensate (bbls)................... 315,998 104,918
Natural gas and gas products (Mcf)................ 492,772 508,750
Crude oil and condensate average price, per bbl... $ 15.46 $ 15.50
Natural gas average price, per Mcf
(excluding gas products)....................... $ 2.43 $ 1.81
Crude oil and condensate revenues................. $ 4,885,361 $ 1,626,664
Natural gas and gas products revenues............. 1,190,369 936,177
Production expenses............................... (1,027,050) (922,980)
Capital expenditures.............................. (1,801,363) (306,268)
Undistributed Net Loss (Income)(2)................ 776,531 (46,481)
(Provision for) Refund of escrowed special costs.. (4,023,848) (237,132)
------------ ------------
NET PROCEEDS...................................... 0 1,049,980
Royalty interest.................................. X 25% X 25%
------------ ------------
Partnership share................................. 0 262,495
Trust interest.................................... X 99.99% X 99.99%
------------ ------------
Trust share....................................... $ 0 $ 262,469
============ ============
(1) The amounts for the three months ended March 31, 1996 and 1995
represent actual production for the periods November 1995 through
January 1996 and November 1994 through January 1995, 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, 1996, the undistributed net loss carryforward was $2,947,172
($736,793 net to the Trust).
-10-
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>
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>
-11-
(B) REPORTS ON FORM 8-K
During the first quarter of 1996, the Trust filed a current report on
Form 8-K, dated January 22, 1996, in connection with Chevron's drilling of the
F-2 delineation gas well on the Ship Shoal 182/183 property. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations" for
further information regarding such drilling.
-12-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
TEL OFFSHORE TRUST
By: Texas Commerce Bank National Association,
Corporate Trustee
By: /S/ MICHAEL J. ULRICH
Michael J. Ulrich
Senior Vice President
and Trust Officer
Date: May 9, 1996
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-
<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-31-1996 AND THE
STATEMENT OF DISTRIBUTABLE INCOME FOR THE THREE MONTHS ENDED MAR-31-1996 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> MAR-31-1996
<CASH> 1,006,836
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,006,836
<PP&E> 28,267,655
<DEPRECIATION> 27,196,037
<TOTAL-ASSETS> 2,078,454
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 1,071,618
<TOTAL-LIABILITY-AND-EQUITY> 2,078,454
<SALES> 0
<TOTAL-REVENUES> 8,687
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 179,783
<LOSS-PROVISION> (171,096)
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 0
<EPS-PRIMARY> .000
<EPS-DILUTED> .000
</TABLE>
