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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 SEPTEMBER 30, 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.)
THE CHASE MANHATTAN BANK
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 November 3, 2000 -- 4,751,510 Units of Beneficial Interest in TEL
Offshore Trust.
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<PAGE>
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-Q are forward-looking
statements. Although the Working Interest Owners (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.
i
<PAGE>
PART I -- FINANCIAL INFORMATION
ITEM 1 -- FINANCIAL STATEMENTS
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
SEPTEMBER 30, DECEMBER 31,
2000 1999
------------- ------------
(UNAUDITED)
ASSETS
Cash and cash equivalents............ $3,063,048 $3,456,123
Net overriding royalty interest in
producing oil and gas properties,
net of accumulated amortization of
$27,964,546 and $27,899,887,
respectively....................... 303,109 367,768
---------- ----------
Total assets......................... $3,366,157 $3,823,891
========== ==========
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit
holders............................ $1,945,564 $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)....................... 303,109 367,768
---------- ----------
Total liabilities and Trust corpus... $3,366,157 $3,823,891
========== ==========
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Royalty income....................... $1,987,518 $ 687,942 $4,561,785 $ 833,397
Interest income...................... 18,671 15,858 53,275 45,361
---------- ---------- ---------- ----------
2,006,189 703,800 4,615,060 878,758
Decrease in reserve for future Trust
expenses........................... 0 (25,258) 266,759 (18,208)
General and administrative
expenses........................... (60,625) (70,569) (221,931) (196,984)
---------- ---------- ---------- ----------
Distributable income................. $1,945,564 $ 607,973 $4,659,888 $ 663,566
========== ========== ========== ==========
Distributions per Unit (4,751,510
Units)............................. $ .409462 $ .127953 $ .980716 $ .139653
========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
1
<PAGE>
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------------- ----------------------------
2000 1999 2000 1999
----------- ---------- ---------- -----------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period.... $ 329,216 $ 437,143 $ 367,768 $ 442,621
Distributable income................. 1,945,564 607,973 3,962,821 663,566
Distribution payable to Unit
holders............................ (1,945,564) (607,973) (3,962,821) (663,566)
Amortization of net overriding
royalty interest................... (26,107) (15,477) (64,659) (20,955)
----------- ---------- ---------- -----------
Trust corpus, end of period.......... $ 303,109 $ 421,666 $ 303,109 $ 421,666
=========== ========== ========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
2
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- TRUST ORGANIZATION
Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL
Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of
Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December 22,
1982. In accordance with the Plan, the TEL Offshore Trust Partnership
("Partnership") was formed in which the Trust owns a 99.99% interest and Tenneco
Oil Company ("Tenneco") initially owned a .01% interest. In general, the Plan
was effected by transferring an overriding royalty interest ("Royalty")
equivalent to a 25% net profits interest in the oil and gas properties (the
"Royalty Properties") of Tenneco Exploration, Ltd. ("Exploration I") located
offshore Louisiana to the Partnership and issuing certificates evidencing units
of beneficial interest in the Trust ("Units") in liquidation and cancellation of
Tenneco Offshore's common stock.
On October 31, 1986, Exploration I was dissolved and the oil and gas
properties of Exploration I were distributed to Tenneco subject to the Royalty.
Tenneco, who was then serving as the Managing General Partner of the
Partnership, assumed the obligations of Exploration I, including its obligations
under the instrument conveying the Royalty to the Partnership (the
"Conveyance"). The dissolution of Exploration I had no impact on future cash
distributions to Unit holders.
On November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired most of the
Gulf of Mexico offshore oil and gas properties of Tenneco, including all the
Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as
the Working Interest Owner and Managing General Partner of the Partnership.
Chevron also assumed Tenneco's obligations under the Conveyance.
On October 30, 1992, 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
<PAGE>
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 will generally 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 The
Chase Manhattan Bank, the successor by merger to 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 that 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
<PAGE>
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 Royalty
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
<PAGE>
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 nine months 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 $1,982,000. The net deposit was primarily a result of an increase
in the Working Interest Owners' current estimate of projected capital
expenditures on the Royalty Properties. In addition, there was a deposit
adjustment of approximately $576,500 made in the second quarter of 1999 due to a
release not being made in fourth quarter 1997. In the first nine months 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 $778,327. The net 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
September 30, 2000, approximately $6,272,000 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 in the
reserve of $266,759 was distributed to Unit holders in the first quarter of
2000.
6
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
NOTE 7 -- COMMITMENTS AND CONTINGENCIES
During 1994, 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 $507,300 has been recovered from the Trust by this Working
Interest Owner through the third quarter of 2000. The remainder will be subject
to recovery from the Trust during future periods in accordance with the
Conveyance. The Working Interest Owner on the Eugene Island 348 property has
advised the Trust that future Royalty income attributable to all of the Royalty
Properties owned by this Working Interest Owner 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 this Working Interest Owner, it
is estimated that Royalty income attributable to such properties will be
retained by this Working Interest Owner for the remaining life of the Trust. The
Trust does not anticipate that retention of such Royalty income by this Working
Interest Owner will have a material effect on the Trust's Royalty income as a
whole.
During the first quarter of 1999, the Working Interest Owner of East
Cameron 371/381 informed the Trust that the Working Interest Owner 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 six months 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 Working Interest Owner informed the Trust in
the third quarter of 1999 that it was required to make additional adjustments to
reported financial information on these properties. These adjustments resulted
from the Working Interest Owner's audit of these Trust properties. This audit
was made by the Working Interest Owner at the request of the Trustees of the
Trust. Adjustments arising from this audit included previous capital
expenditures and exploratory costs not charged to the Trust that were offset by
revenues from plant liquids and oil, as well as revenues attributable to
differences in pricing formulas, that should have been paid to the Trust. After
netting these findings, the Working Interest Owner has informed the Trust that
the loss carryforward projected in the first two quarters of 1999 should be
adjusted and eliminated, and that the Working Interest Owner owes the trust
approximately $80,000.
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
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL REVIEW
THREE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999
Distributions to Unit holders for the three months ended September 30, 2000
amounted to $1,945,564 or $.409462 per Unit as compared to $607,973 or $.127953
per Unit for the same period in 1999. The increase in distributable income for
the third quarter of 2000 was primarily due to increased oil and gas prices,
offset by production volume declines, 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 six months 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 Working Interest Owner informed the Trust in the
third quarter of 1999 that it was required to make additional adjustments to
reported financial information on these properties. These adjustments resulted
from the Working Interest Owner's audit of these Trust properties. This audit
was made by the Working Interest Owner at the request of the Trustees of the
Trust. Adjustments arising from this audit included previous capital
expenditures and exploratory costs not charged to the Trust that were offset by
revenues from plant liquids and oil, as well as revenues attributable to
differences in pricing formulas, that should have been paid to the Trust. After
netting these findings, the Working Interest Owner has informed the Trust that
the loss carryforward projected in the first two quarters of 1999 should be
adjusted and eliminated, and that the Working Interest Owner owes the trust
approximately $80,000. The following summary presents the third quarter of 1999
activity inclusive of this one-time adjustment.
Gas revenues decreased approximately 37% or $1,886,869 in the third quarter
of 2000 compared to the third quarter of 1999 primarily due to a 57% decrease in
gas volumes in the third quarter of 2000 compared to the third quarter of 1999.
The decrease in gas volumes was primarily attributable to increased water
production on the West Cameron 643 A-10 well and the West Cameron 643 A-14 well
in the third quarter of 2000. Both wells are candidates for workovers in 2000.
The decrease in gas volumes was partially offset by a 73% increase in the
average price received for natural gas from $2.31 per thousand cubic feet of gas
("Mcf") in the third quarter of 1999 to $4.00 per Mcf in the third quarter of
2000.
Crude oil and condensate revenues increased approximately 24% or $1,069,861
in the third quarter of 2000 as compared to the same period in 1999 primarily
due to a 70% increase in the average price received from $16.44 per barrel in
the third quarter of 1999 to $27.92 per barrel in the third quarter of 2000. The
increase in average price was partially offset by a 7% decrease in crude oil and
condensate volumes from the 1999 third quarter to the 2000 third quarter.
The Trust's share of capital expenditures decreased approximately 89% or
$692,235 in the third quarter of 2000 as compared to the same period in 1999
primarily due to the A-5 well drilling cost adjustment being recognized in the
third quarter of 1999 on the East Cameron 371/381 property. The Trust's share of
operating expenses decreased by approximately 6% or $16,290 in the third quarter
of 2000 as compared to the same period in 1999 due primarily to the A-5 well
adjustment on the East Cameron 371/381 property in the third quarter of 1999.
For the third quarter of 2000, the Trust had undistributed net income of
$15,842. Undistributed net income represents positive Net Proceeds, generated
during the respective period, that were applied to an
8
<PAGE>
existing loss carryforward. 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). The undistributed net income for the
third quarter of 2000 was primarily related to the loss carryforward referred to
above on the Eugene Island 348 property.
In the third 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 $131,000, compared to a deposit of funds into the Special Cost
Escrow Account of $597,510 to the Trust in the third quarter of 1999. 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.
NINE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999
Distributions to Unit holders for the nine months ended September 30, 2000
amounted to $4,659,888 or $.980716 per Unit as compared to $663,566 or $.139653
per Unit for the same period in 1999. The increase in distributable income for
the first nine months of 2000 was primarily due to increased oil and gas prices,
offset by production volume declines, 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 six months 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 Working Interest Owner informed the Trust in the
third quarter of 1999 that it was required to make additional adjustments to
reported financial information on these properties. These adjustments resulted
from the Working Interest Owner's audit of these Trust properties. This audit
was made by the Working Interest Owner at the request of the Trustees of the
Trust. Adjustments arising from this audit included previous capital
expenditures and exploratory costs not charged to the Trust that were offset by
revenues from plant liquids and oil, as well as revenues attributable to
differences in pricing formulas, that should have been paid to the Trust. After
netting these findings, the Working Interest Owner has informed the Trust that
the loss carryforward projected in the first two quarters of 1999 should be
adjusted and eliminated, and that the Working Interest Owner owes the Trust
approximately $80,000. The following summary presents the first nine months of
1999 activity inclusive of this one-time adjustment.
Gas revenues increased 31% or $2,210,019 in the first nine months of 2000
as compared to the first nine months of 1999 primarily due to a 35% increase in
the average price received for natural gas from $2.21 per Mcf in the first nine
months of 1999 to $2.98 per Mcf in the first nine months of 2000. In addition,
there was a .5% increase in gas volumes.
Crude oil and condensate revenues increased approximately 70% or $7,012,595
in the first nine months of 2000 as compared to the same period in 1999
primarily due to a 92% increase in the average price received from $14.09 per
barrel for the nine months ended September 30, 1999 to $27.05 per barrel for the
nine months ended September 30, 2000. The increase in the average price for
crude oil and condensate was partially offset by an 11% decrease in the crude
oil and condensate volumes.
The Trust's share of capital expenditures decreased by approximately 74% or
$1,036,396 for the nine months ended September 30, 2000 as compared to the same
period in 1999 primarily due to the costs associated with drilling the A -5 well
in the second quarter of 1999 on the East Cameron 371/381 property.
9
<PAGE>
The Trust's share of operating expenses increased by approximately 1% or $9,614
for the nine months ended September 30, 2000 as compared to the same period in
1999.
For the first nine months of 2000, the Trust had undistributed net income
of $60,718. The undistributed net income for the first nine months of 2000 was
primarily related to the loss carryforward referred to above on the Eugene
Island 348 property.
In the first nine months 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 $778,000 compared to a net deposit of funds into the Special Cost
Escrow Account of approximately $1,982,000 net to the Trust in the first nine
months of 1999.
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 in the reserve 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 SEPTEMBER 30, 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 $2,026,917 in the
third quarter of 1999 to $3,554,374 in the third quarter of 2000, primarily due
to an increase in the average crude oil price from $16.91 per barrel in the
third quarter of 1999 to $28.25 per barrel in the third quarter of 2000. In
addition, crude oil production increased from 119,891 barrels in the third
quarter of 1999 to 125,797 barrels in the third quarter of 2000. Gas revenues
decreased from $1,065,787 in the third quarter of 1999 to $780,821 in the third
quarter of 2000 primarily due to a decrease in gas volumes from 465,704 Mcf in
the third quarter
10
<PAGE>
of 1999 to 202,322 Mcf in the third quarter of 2000. This decrease in gas
volumes was due primarily to lower production on the B-15 and E-10 wells in the
third quarter of 2000 and continued natural production decline on the
properties. The B-15 and E-10 wells were recompleted in August 2000. The
decrease in gas volumes was partially offset by an increase in the average
natural gas sales prices from $2.38 per Mcf in the third quarter of 2000 to
$4.02 per Mcf for the same period in 2000. 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 87,141 Mcf have been overtaken by
the Working Interest Owner from this property as of July 31, 2000. The Trust's
share of this overtake position is approximately 21,785 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 decreased $717,579 in the third quarter of 1999
as compared to the third quarter of 2000 due primarily to the costs associated
with the sidetrack drilling on the E-2 well in the third quarter of 1999.
Operating expenses increased from $368,451 in the third quarter of 1999 to
$405,832 for the same period in 2000 due primarily to items previously charged
as capital expenditures being reclassified by a Working Interest Owner after the
completion of drilling as operational expenses in the third quarter of 2000. The
Working Interest Owner has advised the Trust that it plans to drill an E-10
sidetrack well in the fourth quarter of 2000 at an approximate cost of
$1.3 million ($325,000 net to the Trust) and an additional five developmental
and five delineation wells in the year 2001. The Working Interest Owner has
cancelled its plans to drill the E-8 sidetrack.
Eugene Island 339 crude oil revenues increased from $1,180,664 in the third
quarter of 1999 to $1,597,975 for the same period in 2000 primarily due to an
increase in the average crude oil price from $15.49 per barrel in the third
quarter of 1999 to $26.85 per barrel in the third quarter of 2000. The increase
in the average crude oil price was partially offset by a decrease in volumes
from 76,234 barrels in the third quarter of 1999 to 59,521 barrels for the same
period in 2000. Gas revenues decreased from $304,339 in the third quarter of
1999 to $221,236 in the third quarter of 2000 due primarily to a decrease in gas
volumes from 151,486 Mcf in the third quarter of 1999 to 56,448 Mcf for the same
period in 2000. The decrease in gas volumes was due primarily to continued
natural production decline on the properties. The decrease in volumes was
partially offset by an increase in the average price received for natural gas
from $2.22 per Mcf in the third quarter of 1999 to $4.62 per Mcf for the same
period in 2000. The Working Interest Owner has advised the Trust that there is
an overtake imbalance position of approximately 12,922 Mcf on this property as
of July 31, 2000. The Trust's share of this overtake position is approximately
3,231 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 increased by $284,032 from the third quarter of 1999
as compared to the third quarter of 2000 due primarily to A-7 sidetrack drilling
costs being recognized in the third quarter of 2000. Operating expenses
decreased from $389,406 in the third quarter of 1999 to $203,764 in the third
quarter of 2000. The Working Interest Owner has advised the Trust that it plans
to drill a delineation well on this property during the fourth quarter of 2000
at an approximate cost of $2.8 million ($700,000 net to the Trust).
West Cameron 643 gas revenues decreased from $2,453,002 in the third
quarter of 1999 to $1,407,829 in the third quarter of 2000 due primarily to a
decrease in gas volumes from 954,993 Mcf in the third quarter of 1999 to 354,167
Mcf for the same period in 2000. The decrease in gas volumes was due primarily
to increased water production on the A-10 and A-14 wells in the third quarter of
2000 and the continued
11
<PAGE>
natural production decline on these properties. The decrease in gas volumes was
partially offset by an increase in the average price received for natural gas
from $2.31 per Mcf in the third quarter of 1999 to $3.98 per Mcf for the same
period in 2000. 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 25,035 Mcf have been overtaken by the
Working Interest Owner from this property as of July 31, 2000. The Trust's share
of this overtake position is approximately 6,259 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 decreased from
$275,272 in the third quarter of 1999 to $232,177 for the same period in 2000.
Capital expenditures decreased by $43,095 in the third quarter of 1999 as
compared to the same period in 2000.
East Cameron 371/381 crude oil revenue decreased from $932,039 in the third
quarter of 1999 to $179,079 in the third quarter of 2000 due primarily to a
decrease in crude oil production from 11,281 barrels in the third quarter of
1999 to 5,901 barrels in the third quarter of 2000. The decrease in crude oil
production was due primarily to increased water production on the A-1 and A-2
wells in the third quarter of 2000. In addition, there was an upward adjustment
of $734,161 made in the third quarter of 1999 as discussed above. The decrease
in crude oil production was partially offset by an increase in the average crude
oil price from $17.54 per barrel in the third quarter of 1999 to $30.35 per
barrel for the same period in 2000. Gas revenues decreased from $1,002,262 in
the third quarter of 1999 to $479,405 in the third quarter of 2000 due primarily
to a decrease in gas volumes from 235,563 Mcf in the third quarter of 1999 to
130,555 Mcf in the third quarter of 2000. The decrease in gas volumes was due
primarily to increased water production on the A-1 and A-2 wells in the third
quarter of 2000. The decrease in gas volumes was partially offset by an increase
in the average price received for natural gas from $2.36 in the third quarter of
1999 to $3.98 for the same period in 2000. 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 $1,780,482 in the third quarter of 2000 as
compared to the same period in 1999 primarily due to the adjustment made to this
property in the third quarter of 1999 by the Working Interest Owner as discussed
above. Operating expenses increased $110,381 in the third quarter of 2000 as
compared to the same period in 1999 primarily due to the adjustment made to this
property in the third quarter of 1999 by the Working Interest Owner as discussed
above.
NINE MONTHS ENDED SEPTEMBER 30, 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 $5,479,475 in the
first nine months of 1999 to $11,014,759 in the first nine months of 2000,
primarily due to an increase in the average crude oil price from $13.08 per
barrel in the first nine months of 1999 to $27.34 per barrel in the first nine
months of 2000. The increase in the average crude oil price was partially offset
by a decrease in crude oil production from 418,940 barrels in the first nine
months of 1999 to 402,940 barrels for the same period in 2000 due primarily to
continued natural production decline on these properties. Gas revenues decreased
from $2,682,334 in the first nine months of 1999 to $2,236,081 in the first nine
months of 2000 primarily due to a decrease in gas volumes from 1,370,803 Mcf in
the first nine months of 1999 to 766,044 Mcf for the same period in 2000. This
decrease in gas volumes was primarily the result of lower production on the B-15
and
12
<PAGE>
E-10 wells and continued natural production decline on the properties in the
first nine months of 2000. The B-15 and E-10 wells were recompleted in August
2000. The decrease in gas volumes was partially offset by an increase in the
natural gas sales price from $2.04 per Mcf in the first nine months of 1999 to
$3.00 per Mcf in the same period in 2000. Capital expenditures decreased from
$753,020 in the first nine months of 1999 to $160,898 in the same period in 2000
due primarily to the costs associated with the sidetrack drilling on the E-2
well in the third quarter of 1999. Operating expenses increased from $1,091,623
in the first nine months of 1999 to $1,302,472 in the same period in 2000 due
primarily to items previously charged as capital expenditures being reclassified
by a Working Interest Owner after the completion of drilling as operational
expenses in the third quarter of 2000.
Eugene Island 339 crude oil revenues increased from $3,231,124 in the first
nine months of 1999 to $4,835,249 for the same period in 2000 primarily due to
an increase in the average crude oil price from $12.04 per barrel in the first
nine months of 1999 to $26.07 per barrel in the first nine months of 2000. The
increase in the average crude oil price was partially offset by a decrease in
volumes from 268,178 barrels in the first nine months of 1999 to 185,496 barrels
for the same period in 2000. Gas revenues decreased from $878,642 in the first
nine months of 1999 to $762,231 in the first nine months of 2000 due primarily
to a decrease in gas volumes from 457,723 Mcf for the first nine months of 1999
to 263,000 Mcf for the same period in 2000. The decrease in gas volumes was due
primarily to a positive volume adjustment made in the second quarter of 1999,
the compressor being down for 18 days in the second quarter of 2000 and
continued natural production decline on the properties. The decrease in gas
volumes was partially offset by an increase in the average price received for
natural gas from $2.12 per Mcf in the first nine months of 1999 to $3.02 per Mcf
for the same period in 2000. Capital expenditures increased from $279,483 in the
first nine months of 1999 to $1,001,294 for the same period in 2000 due
primarily to the drilling of the B-18 and A-7 sidetrack well and improvements on
the platform B A614 facilities in the first nine months of 2000. Operating
expenses decreased from $1,074,325 in the first nine months of 1999 to $902,045
for the same period in 2000.
West Cameron 643 gas revenues decreased from $4,849,483 in the first nine
months of 1999 to $3,868,070 in the first nine months of 2000 due primarily to a
decrease in gas volumes from 2,198,416 Mcf in the first nine months of 1999 to
1,297,350 Mcf for the same period in 2000. The decrease in gas volumes was
primarily due to the A-10 well being shut down in the first quarter of 2000 for
maintenance work, increased water production on the A-10 and A-14 wells in the
third quarter of 2000 and continued natural production decline on these
properties. Operating expenses increased from $777,880 in the first nine months
of 1999 to $881,208 for the same period in 2000 due primarily to maintenance
work on the B well in the first quarter of 2000. Capital expenditures decreased
from $1,270,627 in the first nine months of 1999 to $109,012 for the same period
in 2000 due primarily to costs associated with bringing the B9-D well online in
the second quarter of 1999.
East Cameron 371/381 crude oil revenues decreased from $907,780 in the
first nine months of 1999 to $713,919 in the first nine months of 2000 due
primarily to an upward adjustment of $734,161 made in the third quarter of 1999
as discussed above. In addition to the upward revenue adjustment, oil production
increased from 9,635 barrels in the first nine months of 1999 to 25,255 barrels
for the same period in 2000. In addition, the average crude oil price increased
from $18.02 per barrel in the first nine months of 1999 to $28.27 per barrel in
the first nine months of 2000. Gas revenues increased $3,605,695 in the first
nine months of 2000 as compared to the same period in 1999 due primarily to an
increase in gas volumes of 1,797,950 Mcf in the first nine months of 2000 as
compared to the same period in 1999. In 1998, 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 (a net adjustment of $1,090,367 to the Trust).
Therefore, an adjustment for this 1998 overpayment was made in the first quarter
of 1999. The Working Interest Owner of East Cameron 371/381 recouped $404,190 of
the overpayment from production in the first six months of
13
<PAGE>
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. In addition, there were upward
adjustments of $69,240 for gas revenues made in the third quarter of 1999 as
discussed above. Capital expenditures decreased from $3,204,674 in the first
nine months of 1999 to $150,651 in the first nine months of 2000 due primarily
to a $1,514,771 upward adjustment made in the third quarter of 1999 as discussed
above. Operating expenses decreased from $171,637 in the first nine months of
1999 to $64,617 in the first nine months of 2000 due primarily to costs
associated with the A-1 well workover in the second quarter of 1999.
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 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 nine months of
1999, there was a deposit of funds into the Special Cost Escrow Account. The
Trust's share of the funds deposited was approximately $1,982,000. The net
deposit was primarily a result of an increase in the Working Interest Owners'
current
14
<PAGE>
estimate of projected capital expenditures on the Royalty Properties. In
addition, there was a deposit adjustment of approximately $576,500 made in the
second quarter of 1999 due to a release not being made in the fourth quarter of
1997. In the first nine months 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 $778,327. The net 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 September 30, 2000, approximately $6,272,000
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.
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
SEPTEMBER 30,(1)
-----------------------------
2000 1999(3)
----------- -----------
Crude oil and condensate (bbls)......... 196,673 212,200
Natural gas and gas products (Mcf)...... 841,699 1,953,263
Crude oil and condensate average price,
per bbl............................... $ 27.92 $ 16.44
Natural gas average price, per Mcf
(excluding gas products).............. $ 4.00 $ 2.31
Crude oil and condensate revenues....... $ 5,490,663 $ 4,420,802
Natural gas and gas products revenues... 3,262,120 5,148,989
Production expenses..................... (908,310) (1,216,448)
Capital expenditures.................... (355,194) (3,124,133)
Undistributed Net Loss (Income)(2)...... (63,367) (87,125)
(Provision for) Refund of escrowed
special costs......................... 524,956 (2,390,041)
----------- -----------
NET PROCEEDS............................ 7,950,868 2,752,044
Royalty interest........................ x25% x25%
----------- -----------
Partnership share....................... 1,987,717 688,011
Trust interest.......................... x99.99% x99.99%
----------- -----------
Trust share............................. $ 1,987,518 $ 687,942
=========== ===========
------------
(1) The amounts for the three months ended September 30, 2000 and 1999 represent
actual production for the periods May 2000 through July 2000, and May 1999
through July 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,
15
<PAGE>
generated during the respective period, that were applied to an existing
loss carryforward. As of September 30, 2000, the loss carryforward was
$954,392 ($238,598 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. The Working
Interest Owner informed the Trust in the third quarter of 1999 that it was
required to make additional adjustments to reported financial information on
these properties. These adjustments resulted from the Working Interest
Owner's audit of these Trust properties. This audit was made by the Working
Interest Owner at the request of the Trustees of the Trust. Adjustments
arising from this audit included previous capital expenditures and
exploratory costs not charged to the Trust that were offset by revenues from
plant liquids and oil, as well as revenues attributable to differences in
pricing formulas, that should have been paid to the Trust. After netting
these findings, the Working Interest Owner has informed the Trust that the
loss carryforward projected in the first two quarters of 1999 should be
adjusted and eliminated, and that the Working Interest Owner owes the Trust
approximately $80,000.
ROYALTY PROPERTIES
NINE MONTHS ENDED
SEPTEMBER 30,(1)
-----------------------------
2000 1999(3)
----------- -----------
Crude oil and condensate (bbls)......... 629,699 711,100
Natural gas and gas products (Mcf)...... 3,196,601 3,182,162
Crude oil and condensate average price,
per bbl............................... $ 27.05 $ 14.09
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.98 $ 2.21
Crude oil and condensate revenues....... $17,033,945 $10,021,350
Natural gas and gas products revenues... 9,379,270 7,169,251
Production expenses..................... (3,343,155) (3,533,259)
Capital expenditures.................... (1,464,915) (5,610,497)
Undistributed Net Loss (Income)(2)...... (242,874) 3,214,993
(Provision for) Refund of escrowed
special costs......................... (3,113,307) (7,927,918)
----------- -----------
NET PROCEEDS............................ 18,248,964 3,333,920
Royalty interest........................ x25% x25%
----------- -----------
Partnership share....................... 4,562,241 833,480
Trust interest.......................... x99.99% x99.99%
----------- -----------
Trust share............................. $ 4,561,785 $ 833,397
=========== ===========
------------
(1) The amounts for the nine months ended September 30, 2000 and 1999 represent
actual production for the periods November 1999 through July 2000, and
November 1998 through July 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 September 30, 2000, the loss carryforward
was $954,392 ($238,598 net to the Trust).
16
<PAGE>
(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. The Working
Interest Owner informed the Trust in the third quarter of 1999 that it was
required to make additional adjustments to reported financial information on
these properties. These adjustments resulted from the Working Interest
Owner's audit of these Trust properties. This audit was made by the Working
Interest Owner at the request of the Trustees of the Trust. Adjustments
arising from this audit included previous capital expenditures and
exploratory costs not charged to the Trust that were offset by revenues from
plant liquids and oil, as well as revenues attributable to differences in
pricing formulas, that should have been paid to the Trust. After netting
these findings, the Working Interest Owner has informed the Trust that the
loss carryforward projected in the first two quarters of 1999 should be
adjusted and eliminated, and that the Working Interest Owner owes the Trust
approximately $80,000.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Reference is made to Item 1 of this Form 10-Q.
17
<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> <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 third quarter of 2000.
18
<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: The Chase Manhattan Bank,
Corporate Trustee
By: /s/ PETE FOSTER
-----------------------------------
PETE FOSTER
SENIOR VICE PRESIDENT
AND TRUST OFFICER
Date: November 13, 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.
19
