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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2000
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.)
CHASE BANK OF TEXAS,
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 8, 2000 -- 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 (as defined herein) 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
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
MARCH 31, DECEMBER 31,
2000 1999
---------- ------------
(UNAUDITED)
ASSETS
Cash and cash equivalents............ $2,575,833 $ 3,456,123
Net overriding royalty interest in
producing oil and gas properties,
net of accumulated amortization of
$27,919,438 and $27,899,887,
respectively....................... 348,217 367,768
---------- ------------
Total assets......................... $2,924,050 $ 3,823,891
========== ============
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit
holders............................ $1,458,349 $ 2,071,880
Reserve for future Trust expenses.... 1,117,484 1,384,243
Commitments and contingencies
(Note 7)...........................
Trust corpus (4,751,510 Units of
beneficial interest authorized and
outstanding)....................... 348,217 367,768
---------- ------------
Total liabilities and Trust corpus... $2,924,050 $ 3,823,891
========== ============
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
--------------------------
2000 1999
------------ ------------
Royalty income....................... $ 1,251,181 $ 88,696
Interest income...................... 18,017 15,832
------------ ------------
1,269,198 104,528
Decrease (increase) in reserve for
future Trust expenses.............. 266,759 (18,208)
General and administrative
expenses........................... (77,608) (30,727)
------------ ------------
Distributable income................. $ 1,458,349 $ 55,593
============ ============
Distributions per Unit (4,751,510
Units)............................. $ .306923 $ .011700
============ ============
The accompanying notes are an integral part of these financial statements.
1
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STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
----------------------------
2000 1999
-------------- ------------
Trust corpus, beginning of period.... $ 367,768 $ 442,621
Distributable income................. 1,458,349 55,593
Distribution payable to Unit
holders............................ (1,458,349) (55,593)
Amortization of net overriding
royalty interest................... (19,551) (3,732)
-------------- ------------
Trust corpus, end of period.......... $ 348,217 $ 438,889
============== ============
The accompanying notes are an integral part of these financial statements.
2
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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, PennzEnergy Company ("PennzEnergy") acquired certain
oil and gas producing properties from Chevron, including four of the Royalty
Properties. The four Royalty Properties acquired by PennzEnergy were East
Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a
result of such acquisition, PennzEnergy replaced Chevron as the Working Interest
Owner of such properties on October 30, 1992. PennzEnergy also assumed Chevron's
obligations under the Conveyance with respect to such properties.
On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco")
acquired two of the Royalty Properties from Chevron. The Royalty Properties
acquired by Texaco were West Cameron 643 and East Cameron 371/381. As a result
of such acquisitions, Texaco replaced Chevron as the Working Interest Owner of
such properties on December 1, 1994. Texaco also assumed Chevron's obligations
under the Conveyance with respect to such properties.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced
PennzEnergy as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, on October 1, 1995 and also assumed
PennzEnergy's obligations under the Conveyance with respect to such properties.
Effective January 1, 1998, Energy Resource Technology, Inc. ("Energy")
acquired the East Cameron 354 property from SONAT. As a result of such
acquisition, Energy replaced SONAT as the Working Interest Owner of the East
Cameron 354 property effective January 1, 1998, and also assumed SONAT's
obligations under the Conveyance with respect to such property. In October 1998,
Amerada Hess Corporation ("Amerada") acquired the East Cameron 354 property
from Energy effective January 1, 1998. As a result of such acquisition, Amerada
replaced Energy as the Working Interest Owner of the East
3
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TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
Cameron 354 property effective January 1, 1998, and also assumed Energy's
obligations under the Conveyance with respect to such property.
Effective January 1, 2000 PennzEnergy and Devon Energy Corporation (Nevada)
merged into Devon Energy Production Company L.P., ("Devon"). As a result of
such merger, Devon replaced PennzEnergy as the Working Interest Owner of Eugene
Island 348 and Eugene Island 208 properties effective January 1, 2000, and also
assumed PennzEnergy'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 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 and East Cameron
371/381 thereafter; PennzEnergy 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 until January 1, 2000; Texaco with respect to West Cameron 643 and East
Cameron 371/381 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; and Amerada with respect to East Cameron 354 for periods
beginning on or after January 1, 1998; and Devon with respect to Eugene Island
348 and Eugene Island 208 for periods beginning on or after January 1, 2000).
NOTE 2 -- BASIS OF ACCOUNTING
The accompanying unaudited financial information has been prepared by Chase
Bank of Texas, 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, 1999.
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
4
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TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
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 on a units-of-production basis, 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.
Impairment of Long-Lived Assets. The Trust reviews net overriding royalty
interest in oil and gas properties for possible impairment whenever events or
circumstances indicate the carrying amount of the asset may not be recoverable.
If there is an indication of impairment, the Trust prepares an estimate of
future cash flows (undiscounted and without interest charges) expected to result
from the use of the asset and its eventual disposition. If these cash flows are
less than the carrying amount of the asset, an impairment loss is recognized to
write down the asset to its estimated fair value. Preparation of estimated
expected future cash flows is inherently subjective and is based on management's
best estimate of assumptions concerning expected future conditions. There were
no write downs taken in the periods presented.
NOTE 3 -- NET 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 from the Royalty
Properties less operating and capital costs incurred, management fees and
expense reimbursements owing to the Managing General Partner of the Partnership,
applicable taxes other than income taxes, and a special cost reserve. The
Special Cost Reserve Account is established 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 the reserve of 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 certain factors, including estimates of aggregate future
production costs, aggregate future Special Costs,
5
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TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
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 1999, there was a net deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $461,000. The deposit was primarily a result of an increase in the
Working Interest Owners' current estimate of projected capital expenditures on
the Royalty Properties. In the first quarter of 2000, there was a net deposit of
funds into the Special Cost Escrow Account. The Trust's share of the funds
deposited was approximately $265,000. The deposit was primarily a result of an
increase in the Working Interest Owners' current estimate of projected capital
expenditures of the Royalty Properties. As of March 31, 2000, approximately
$5,758,000 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 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
In the first quarter of 1998, the Trust determined that the Trust's cash
reserve was currently sufficient to provide for future administrative expenses
in connection with the winding up of the Trust. The Trust determined that a cash
reserve equal to three times the average expenses of the Trust during each of
the past three years was sufficient at this time to provide for future
administrative expenses in connection with the winding up of the Trust. This
reserve amount for 1998 was $1,366,035. The excess amount in the reserve of
$106,654 was distributed to Unit holders in the first quarter of 1998, and no
deposits were made to the Trust's cash reserve account during 1998. The reserve
amount for 1999 was $1,384,243. A deposit of $18,208 was made to the Trust's
cash reserve account in the first quarter of 1999. During the second quarter of
1999, the Trust used $25,258 from the Trust's cash reserve account to pay the
Trust's general and administrative expenses, when Royalty income received by the
Trust was insufficient to cover these expenses. This $25,258 was redeposited to
the Trust's cash reserve account from Royalty income during the third quarter of
1999. The reserve amount for 2000 is $1,117,484. The excess amount of $266,759
was distributed to Unit holders in the first quarter of 2000.
6
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TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
NOTE 7 -- COMMITMENTS AND CONTINGENCIES
During 1994, PennzEnergy, 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 $469,300 has been recovered from the Trust by
PennzEnergy through the first quarter of 2000. The remainder will be subject to
recovery from the Trust during future periods in accordance with the Conveyance.
PennzEnergy has advised the Trust that future Royalty income attributable to all
of the Royalty Properties owned by PennzEnergy 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 PennzEnergy, it is estimated
that Royalty income attributable to such properties will be retained by
PennzEnergy for the remaining life of the Trust. The Trust does not anticipate
that retention of such Royalty income by PennzEnergy 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.
7
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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, 2000 AND 1999
Distributions to Unit holders for the three months ended March 31, 2000
amounted to $1,458,349 or $.306923 per Unit as compared to $55,593 or $.011700
per Unit for the same period in 1999. The increase in distributable income for
the first quarter of 2000 was primarily due to a net release of $264,979 from
the Trust's Special Cost Escrow Account as compared to a deposit of $461,000 in
the first quarter of 1999 and the $404,190 recoupment by the Working Interest
Owner of East Cameron 371/381 in the first quarter of 1999 as described below.
During the first quarter of 1999, the Trust discovered that the Working
Interest Owner of East Cameron 371/381 had overpaid royalties to the Trust in
the third and fourth quarters of 1998 in an amount totaling $1,090,367. The
Working Interest Owner of East Cameron 371/381 recouped $404,190 of the
overpayment from production in the first quarter of 1999 and will recoup
additional royalties of $686,177 in future periods through future production on
this property and West Cameron 643, which properties are operated by this
Working Interest Owner. The following summary presents the first quarter of 1999
activity inclusive of this one-time adjustment.
Gas revenues increased $4,487,963 in the first quarter of 2000 compared to
the first quarter of 1999 primarily due to an 1,855,101 Mcf increase in gas
volumes in the first quarter of 2000 compared to the first quarter of 1999. The
increase in gas volumes was primarily attributable to the one-time adjustment
referred to above on the East Cameron 371/381 property. In addition, there was a
21% increase in the average price received for natural gas from $2.11 per Mcf in
the first quarter of 1999 to $2.55 per Mcf in the first quarter of 2000.
Crude oil and condensate revenues increased approximately 105% in the first
quarter of 2000 as compared to the same period in 1999 primarily due to a 150%
increase in the average price received from $10.09 per barrel in the first
quarter of 1999 to $25.22 per barrel in the first quarter of 2000. The increase
in average price was partially offset by an 18% decrease in crude oil and
condensate volumes from the 1999 first quarter to the 2000 first quarter due
primarily to the one-time adjustment referred to above on the East Cameron
371/381 property.
The Trust's share of capital expenditures increased approximately 13% or
$114,448 in the first quarter of 2000 as compared to the same period in 1999
primarily due to drilling activities on the B-18 sidetrack well and improvements
on the platform B facilities on the Eugene Island 339 property in the first
quarter of 2000. The Trust's share of operating expenses increased by
approximately 35% or $347,239 in the first quarter of 2000 as compared to the
same period in 1999 due primarily to maintenance work on the West Cameron 643B
property in the first quarter of 2000.
For the first quarter of 2000, the Trust had undistributed net income of
$22,687. Undistributed net loss represents negative Net Proceeds generated
during the respective period. Undistributed net income represents positive Net
Proceeds, generated during the respective period, that were applied to an
existing loss carryforward. An undistributed net loss is carried forward and
offset, in future periods, by positive Net Proceeds earned by the related
Working Interest Owner(s). The undistributed net income for the first quarter of
2000 was primarily related to the loss carryforward referred to above on the
Eugene Island 348 property.
In the first quarter of 2000, there was a net release of funds from the
Special Cost Escrow Account. The Trust's share of the funds released was
approximately $264,979, compared to a deposit of funds into the Special Cost
Escrow Account of $461,000 net to the Trust in the first quarter of 1999. The
Special Cost
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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. In the
first quarter of 1998, the Trust determined that the Trust's cash reserve was
currently sufficient to provide for future administrative expenses in connection
with the winding up of the Trust. The Trust determined that a cash reserve equal
to three times the average expenses of the Trust during each of the past three
years was sufficient at this time to provide for future administrative expenses
in connection with the winding up of the Trust. This reserve amount for 1998 was
$1,366,035. The excess amount in the reserve of $106,654 was distributed to Unit
holders in the first quarter of 1998, and no deposits were made to the Trust's
cash reserve account during 1998. The reserve amount for 1999 was $1,384,243. A
deposit of $18,208 was made to the Trust's cash reserve account in the first
quarter of 1999. During the second quarter of 1999, the Trust used $25,258 from
the Trust's cash reserve account to pay the Trust's general and administrative
expenses, when Royalty income received by the Trust was insufficient to cover
these expenses. This $25,258 was redeposited to the Trust's cash reserve account
from Royalty income during the third quarter of 1999. The reserve amount for
2000 is $1,117,484. The excess amount of $266,759 was distributed to Unit
holders in the first quarter of 2000.
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, 2000 AND 1999
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 $1,744,388 in the
first quarter of 1999 to $3,125,806 in the first quarter of 2000, primarily due
to an increase in the average crude oil price from $10.61 per barrel in the
first quarter of 1999 to $25.41 per barrel for the same period in 2000. The
increase in the average crude oil price was partially offset by a decrease in
crude oil production from 164,425 barrels in the first quarter of 1999 to
123,037 barrels in the first quarter of 2000. The decrease in crude oil
production was due primarily to the continued natural production decline of
these properties. Gas revenues increased from $531,939 in the first quarter of
1999 to $766,292 in the first quarter of 2000 primarily due to an increase in
the average natural gas sales price from $1.94 per Mcf in the first quarter of
1999 to $2.52 per Mcf for the same period in 2000. In addition, there was an
increase in gas volumes from 284,721 Mcf in the first quarter of 1999 to 310,347
Mcf in the first quarter of 2000. The increase in gas volumes was primarily due
to the E-10 well being watered out in the first quarter of 1999. The gas from
Ship Shoal 182/183 is committed to Dynegy Inc. ("Dynegy") at a calculated
price based on the monthly Inside FERC Tennessee-Louisiana Zone 1 Index. In
addition, the Working Interest Owner has advised the Trust that approximately
9
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100,963 Mcf have been overtaken by the Working Interest Owner from this property
as of January 31, 2000. The Trust's share of this overtake position is
approximately 25,241 Mcf. Accordingly, gas revenues from this property may be
decreased in future periods while underproduced parties recoup 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 $15,990
in the first quarter of 1999 to $160,129 in the first quarter of 2000 primarily
due to sumpwork on the C well and reservoir stimulation on the C and E wells in
the first quarter of 2000. Operating expenses increased from $358,283 in the
first quarter of 1999 to $454,064 for the same period in 2000 primarily due to
increased expenditures.
Eugene Island 339 crude oil revenues increased from $973,740 in the first
quarter of 1999 to $1,685,752 for the same period in 2000 due primarily to an
increase in the average crude oil price from $9.72 per barrel in the first
quarter of 1999 to $24.39 per barrel in the first quarter of 2000. The increase
in the average crude oil price was partially offset by a decrease in volumes
from 100,148 barrels in the first quarter of 1999 to 69,118 barrels in the first
quarter of 2000 due primarily to the continued natural production decline of
these properties. Gas revenues increased from $184,691 in the first quarter of
1999 to $265,705 in the first quarter of 2000 primarily due to an increase in
the average price received for natural gas from $2.07 per Mcf in the first
quarter of 1999 to $2.40 per Mcf for the same period in 2000. In addition, there
was an increase in gas volumes from 98,202 Mcf in the first quarter of 1999 to
112,312 Mcf in the first quarter of 2000 primarily due to an underdelivery in
the fourth quarter 1999. The Working Interest Owner has advised the Trust that
there is an overtake imbalance position of approximately 13,563 Mcf on this
property as of January 31, 2000. The Trust's share of this overtake position is
approximately 3,391 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 Dynegy at a calculated price based on the monthly Inside FERC
Tennessee-Louisiana Zone 1 Index. Capital expenditures decreased from $576,865
in the first quarter of 1999 to $519,352 in the first quarter of 2000. Operating
expenses increased from $376,537 in the first quarter of 1999 to $391,922 in the
first quarter of 2000. The Working Interest Owner has advised the Trust that it
plans to drill a delineation well on this property during the second and third
quarters of 2000 at an approximate cost of $2.8 million ($700,000 net to the
Trust).
West Cameron 643 gas revenues increased from $1,284,949 in the first
quarter of 1999 to $1,328,252 in the first quarter of 2000 primarily due to an
increase in the average price received for natural gas from $2.00 per Mcf in the
first quarter of 1999 to $2.58 per Mcf in the first quarter of 2000. The
increase in the average price received was partially offset by a decrease in gas
volumes from 641,400 Mcf in the first quarter of 1999 to 513,897 Mcf for the
same period in 2000. The decrease in volumes was primarily due to the A-10 well
being shut down in the first quarter of 2000 for maintenance work. The gas from
West Cameron 643 is currently committed to Texaco Natural Gas Inc. ("TNGI").
TNGI is a wholly owned affiliate of Texaco Exploration and Production Inc.
("TEPI"). TNGI purchases natural gas from TEPI and resells such gas to a
variety of third-party customers at a variety of downstream delivery points. The
prices that TNGI pays TEPI for the gas production is based on the actual sale
prices that TNGI receives from its third-party customers less the actual
transportation cost, if any, that TNGI pays to a transporting pipeline. TEPI's
proceeds are based on 100% of the actual resale price of the gas, less actual
transportation. The Working Interest Owner has advised the Trust that
approximately 17,338 Mcf have been overtaken by the Working Interest Owner from
this property as of January 31, 2000. The Trust's share of this overtake
position is approximately 4,335 Mcf. Accordingly, gas revenues from this
property may be reduced in future periods while underproduced parties recover
their share of the gas imbalance. Operating expenses increased from $189,646 in
the first quarter of 1999 to $426,197 for the same period in 2000 primarily due
10
<PAGE>
to maintenance work on the B well in the first quarter of 2000. Capital
expenditures increased from $40,043 in the first quarter of 1999 to $99,194 as
compared to the same period in 2000, due primarily to perforating and test work
done on the A-10 sidetrack well in the first quarter of 2000.
East Cameron 371/381 crude oil revenues increased from $30,128 in the first
quarter of 1999 to $276,154 in the first quarter of 2000 primarily due to an
increase in crude oil production from 2,536 barrels in the first quarter of 1999
to 10,528 barrels for the same period in 2000. In addition, there was an
increase in the average crude oil price from $11.88 per barrel in the first
quarter of 1999 to $26.23 per barrel in the first quarter of 2000. Gas revenues
decreased from $796,839 in the first quarter of 1999 to $562,872 in the first
quarter of 2000 primarily due to a decrease in gas volumes from 362,647 Mcf in
the first quarter of 1999 to 225,905 Mcf for the same period in 2000. The
decrease in gas volumes was partially offset by an increase in the average price
received for natural gas from $2.20 per Mcf in the first quarter of 1999 to
$2.56 per Mcf in the first quarter of 2000. However, in 1998, the gas revenues
and volumes included overpaid revenues and volumes made by the Working Interest
Owner of $4,272,556 and 2,071,162 Mcf, respectively. Therefore, the adjustment
for this 1998 overpayment was made in the first quarter of 1999. The gas from
East Cameron 371/381 is currently committed to TNGI on terms similar to gas
committed to West Cameron 643. Capital expenditures decreased from $193,656 in
the first quarter of 1999 to $177,512 in the first quarter of 2000. Operating
expenses increased from $31,827 in the first quarter of 1999 to $34,254 in the
first quarter of 2000.
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, 1999
future net revenues attributable to the Trust's royalty interests approximated
$22.7 million. Such reserve study also indicates that approximately 75% of the
future net revenues from the Royalty Properties are expected to be received by
the Trust during the next three 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 1999 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
11
<PAGE>
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 1999, there was a deposit
of funds into the Special Cost Escrow Account. The Trust's share of the funds
deposited was approximately $461,000. The deposit was primarily a result of an
increase in the Working Interest Owners' current estimate of projected capital
expenditures on the Royalty Properties. In the first quarter of 2000, there was
a net deposit of funds into the Special Cost Escrow Account. The Trust's share
of the funds deposited was approximately $265,000. The deposit was primarily a
result of an increase in the Working Interest Owners' current estimate of
projected capital exenditures of the Royalty Properties. As of March 31, 2000,
approximately $5,758,000 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.
12
<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)
------------------------------
2000 1999(3)
-------------- --------------
Crude oil and condensate (bbls)......... 208,346 254,171
Natural gas and gas products (Mcf)...... 1,287,141 (567,960)
Crude oil and condensate average price,
per bbl............................... $ 25.22 $ 10.09
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.55 $ 2.11
Crude oil and condensate revenues....... $ 5,254,985 $ 2,564,158
Natural gas and gas products revenues... 3,242,830 (1,245,133)
Production expenses..................... (1,374,245) (937,221)
Capital expenditures.................... (967,684) (853,236)
Undistributed Net Loss (Income)(2)...... (90,746) 2,670,179
(Provision for) Refund of escrowed
special costs......................... (1,059,916) (1,843,927)
-------------- --------------
NET PROCEEDS............................ 5,005,224 354,820
Royalty interest........................ x25% x25%
-------------- --------------
Partnership share....................... 1,251,306 88,705
Trust interest.......................... x99.99% x99.99%
-------------- --------------
Trust share............................. $ 1,251,181 $ 88,696
============== ==============
- ------------
(1) The amounts for the three months ended March 31, 2000 and 1999 represent
actual production for the periods November 1999 through January 2000, and
November 1998 through January 1999, 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, 2000, the loss carryforward was
$1,106,504 ($276,626 net to the Trust).
(3) During the first quarter of 1999, the Working Interest Owner of East Cameron
371/381 informed the Trust that the Working Interest Owner overpaid East
Cameron 371/381 royalties, related primarily to natural gas production, to
the Trust in the third and fourth quarters of 1998. The total gas revenue
and volume reported to the Trust was $5,696,741 ($1,424,185 net to the
Trust) and 2,761,549 Mcf (690,387 Mcf net to the Trust), respectively. The
amount that should have been reported to the Trust for gas revenue and
volume was $1,424,185 ($356,046 net to the Trust) and 690,387 Mcf (172,597
Mcf net to the Trust), respectively. As a result of these miscalculations
and other minor adjustments, the Working Interest Owner overpaid the Trust
royalties totaling $1,090,367. The Working Interest Owner of East Cameron
371/381 recouped $404,190 of the overpayment from production in the first
quarter of 1999 and will recoup additional royalties of $686,177 in future
periods through future production on this property and West Cameron 643,
which properties are operated by this Working Interest Owner.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Reference is made to Item 1 of this Form 10-Q.
13
<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
------------- -------
<C> <S> <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 2000.
14
<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: Chase Bank of Texas, National
Association, Corporate Trustee
By: /s/ PETE FOSTER
-----------------------------------
PETE FOSTER
SENIOR VICE PRESIDENT
AND TRUST OFFICER
Date: May 11, 2000
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.
15
<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-31-2000 AND THE
STATEMENT OF DISTRIBUTABLE INCOME FOR THE THREE MONTHS ENDED MAR-31-2000 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> MAR-31-2000
<CASH> 2,575,833
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,575,833
<PP&E> 28,267,655
<DEPRECIATION> 27,919,438
<TOTAL-ASSETS> 2,924,050
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 348,217
<TOTAL-LIABILITY-AND-EQUITY> 2,924,050
<SALES> 0
<TOTAL-REVENUES> 1,269,198
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 189,151
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 1,458,349
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1,458,349
<EPS-BASIC> .306
<EPS-DILUTED> .306
</TABLE>
