<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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 SEPTEMBER 30, 1999
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
------------------------
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 November 8, 1999 -- 4,751,510 Units of Beneficial Interest in TEL
Offshore Trust.
================================================================================
<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,
1999 1998
------------- ------------
(UNAUDITED)
ASSETS
Cash and cash equivalents............ $ 1,992,216 $3,077,569
Net overriding royalty interest in
producing oil and gas properties,
net of accumulated amortization of
$27,845,989 and
$27,825,034, respectively.......... 421,666 442,621
------------- ------------
Total assets......................... $ 2,413,882 $3,520,190
============= ============
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit
holders............................ $ 607,973 $1,711,534
Reserve for future Trust expenses.... 1,384,243 1,366,035
Commitments and contingencies (Note
7).................................
Trust corpus (4,751,510 Units of
beneficial interest authorized and
outstanding)....................... 421,666 442,621
------------- ------------
Total liabilities and Trust corpus... $ 2,413,882 $3,520,190
============= ============
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------- --------------------------
1999 1998 1999 1998
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Royalty income....................... $ 687,942 $ 896,202 $ 833,397 $ 3,946,589
Interest income...................... 15,858 15,348 45,361 51,530
------------ ------------ ------------ ------------
703,800 911,550 878,758 3,998,119
Decrease (increase) in reserve for
future Trust expenses.............. (25,258) -- (18,208) 106,654
General and administrative
expenses........................... (70,569) (101,180) (196,984) (314,369)
------------ ------------ ------------ ------------
Distributable income................. $ 607,973 $ 810,370 $ 663,566 $ 3,790,404
============ ============ ============ ============
Distributions per Unit (4,751,510
Units)............................. $ .127953 $ .170549 $ .139653 $ .797724
============ ============ ============ ============
</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,
-------------------------- ----------------------------
1999 1998 1999 1998
------------ ------------ ------------ --------------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period.... $ 437,143 $ 593,582 $ 442,621 $ 703,214
Distributable income................. 607,973 810,369 663,566 3,790,403
Distribution payable to Unit
holders............................ (607,973) (810,369) (663,566) (3,790,403)
Amortization of net overriding
royalty interest................... (15,477) (34,893) (20,955) (144,525)
------------ ------------ ------------ --------------
Trust corpus, end of period.......... $ 421,666 $ 558,689 $ 421,666 $ 558,689
============ ============ ============ ==============
</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.
3
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
As a result of such acquisition, Amerada replaced Energy as the Working Interest
Owner of the East Cameron 354 property effective January 1, 1998, and also
assumed Energy's obligations under the Conveyance with respect to such property.
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 thereafter; 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). PennzEnergy was acquired by Devon Energy Corp. in 1999.
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, 1998.
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income is recorded when received by the Corporate Trustee
on the last business day of each calendar quarter; and
(b) Trust general and administrative expenses are recorded when paid,
except for the cash reserved for future general and
administrative expenses, as discussed in Note 6.
This manner of reporting income and expenses is considered to be the most
meaningful because the quarterly distributions to Unit holders are based on net
cash receipts received from the Working Interest Owners. The financial
statements of the Trust differ from financial statements prepared in accordance
with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would
be recognized on an accrual basis. In addition, amortization
4
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
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.
NOTE 3 -- OVERRIDING ROYALTY INTEREST
The Royalty entitles the Trust to its share (99.99%) of 25% of the Net
Proceeds attributable to the Royalty Properties. The Conveyance, dated January
1, 1983, provides that the Working Interest Owners will calculate, for each
period of three months commencing the first day of February, May, August and
November, an amount equal to 25% of the Net Proceeds from their oil and gas
properties for the period. Generally, Net Proceeds are the amounts received by
the Working Interest Owners from the sale of minerals 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, 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
5
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
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 1998, there was a net release of funds from the Special Cost
Escrow Account. The Trust's share of the funds released was approximately
$1,015,000. The release was primarily a result of a decrease in the estimate of
projected capital expenditures of the Royalty Properties. 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 deposit was primarily a result of an increase in the 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. As of September 30, 1999,
approximately $5,888,000 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
At December 31, 1991, a cash reserve of $120,000 had been established for
future Trust general and administrative expenses. During 1992 and 1993, in
anticipation of future periods when the cash received from the Royalty may not
be sufficient for payment of Trust expenses, the reserve for future Trust
general and administrative expenses was increased each quarter by an amount
equal to the difference between $150,000 and the amount of the Trust's general
and administrative expenses for such quarter. In 1994, in anticipation of future
periods when the cash received from the Royalty may not be sufficient for
payment of Trust expenses, the Trust determined, in accordance with the Trust
Agreement, to begin further increasing the Trust's cash reserve each quarter by
an amount equal to the difference between $200,000 and the amount of the Trust's
general and administrative expenses for such quarter. During 1994 and 1995, the
aggregate amount of cash reserved by the Trust was $347,638 and $370,258,
respectively. During 1996, the Trust used $397,845 from the Trust's cash reserve
account to pay the Trust's general and administrative expenses for the first,
second and fourth quarters, when no royalty income was received by the Trust. In
the third quarter of 1996, when Royalty income was received, the Trust reserved
$99,536. Therefore, the net cash used from the Trust's cash reserve account in
1996 was $298,309. During 1997, the aggregate amount of cash reserved by the
Trust was $593,066. 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 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
6
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
Trust's general and administrative expenses, when insufficient royalty income
was received by the Trust. This $25,258 was redeposited to the Trust's cash
reserve account during the third quarter of 1999.
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 $426,300 has been recovered from the Trust by
PennzEnergy through the third quarter of 1999. The remainder will be subject to
recovery from the Trust in 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.
During the first quarter of 1999, Texaco, the Working Interest Owner of
East Cameron 371/381 informed the Trust that it overpaid royalties to the Trust
in the third and fourth quarters of 1998 in an amount totaling $1,090,367.
Texaco recouped $404,190 of the overpayment from production in the first six
months of 1999 and was to recoup additional royalties of $686,177 in future
periods through future production on this property and West Cameron 643, which
properties are operated by Texaco. Texaco informed the Trust in the third
quarter of 1999 that it is now required to make additional adjustments to
reported financial information on these properties. These adjustments resulted
from Texaco's audit of these Trust properties. This audit was made by Texaco 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, Texaco has informed the Trust
that the loss carryforward projected in the last two Trust quarters should be
adjusted and eliminated, and that Texaco 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, 1999 AND 1998
Distributions to Unit holders for the three months ended September 30, 1999
amounted to $607,973 or $.127953 per Unit as compared to $810,370 or $.170549
per Unit for the same period in 1998. The decrease in distributable income for
the third quarter of 1999 was primarily due to a deposit of $597,500 into the
Trust's Special Cost Escrow Account as compared to a net deposit of $307,400 in
the third quarter of 1998.
During the first quarter of 1999, Texaco, the Working Interest Owner of
East Cameron 371/381 informed the Trust that it overpaid royalties to the Trust
in the third and fourth quarters of 1998 in an amount totaling $1,090,367.
Texaco recouped $404,190 of the overpayment from production in the first six
months of 1999 and was to recoup additional royalties of $686,177 in future
periods through future production on East Cameron 371/381 and West Cameron 643,
which properties are operated by Texaco. Texaco informed the Trust in the third
quarter of 1999 that it is now required to make additional adjustments to
reported financial information on these properties. These adjustments resulted
from Texaco's audit of these Trust properties. This audit was made by Texaco 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, Texaco has informed the Trust
that the loss carryforward projected in the last two Trust quarters should be
adjusted and eliminated, and that Texaco owes the Trust approximately $80,000.
The following summary presents the third quarters of 1998 and 1999 activity
inclusive of these adjustments.
Gas revenues decreased approximately 43% in the third quarter of 1999 as
compared to the third quarter of 1998 primarily due to a 51% decrease in gas
volumes. The decrease in gas volumes was primarily attributable to the
adjustments referred to above on the East Cameron 371/381 property. In addition
the E-2 well was shut-in in the third quarter of 1999 on the Ship Shoal 182/183
property. The decrease in gas volumes was partially offset by a 2% increase in
the average price received for natural gas from $2.27 per Mcf in the third
quarter of 1998 to $2.31 per Mcf in the third quarter of 1999.
Crude oil and condensate revenues decreased approximately 1% in the third
quarter of 1999 as compared to the same period in 1998 primarily due to the
adjustments referred to above on the East Cameron 371/381 property. In addition
the average price received for crude oil and condensate increased 33% from
$12.33 per barrel in the third quarter of 1998 to $16.44 per barrel in the third
quarter of 1999. The increase in the average price was partially offset by a 41%
decrease in crude oil and condensate volumes.
The Trust's share of capital expenditures decreased approximately 53% or
$868,592 in the third quarter of 1999 as compared to the same period in 1998
primarily due to costs incurred in the third quarter of 1998 that were
associated with drilling the B-7, B-9 and B-12 wells in the first quarter of
1998, and the B-16 well in the second quarter of 1998, on the Eugene Island 339
property. The Trust's share of operating expenses decreased by approximately 38%
or $152,042 in the third quarter of 1999 as compared to the same period in 1998
due primarily to the workover on the A-17 well on the West Cameron 643 property
in the second quarter of 1998.
For the third quarter of 1999, the Trust had undistributed net income of
$21,781. Undistributed net income represents positive Net Proceeds, generated
during the respective period, that were applied to an
8
<PAGE>
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).
In the third 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
$597,510, compared to a net deposit of funds into the Special Cost Escrow
Account of $307,435 net to the Trust in the third quarter of 1998. 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, 1999 AND 1998
Distributions to Unit holders for the nine months ended September 30, 1999
amounted to $663,566 or $.139653 per Unit as compared to $3,790,404 or $.797724
per Unit for the same period in 1998. The decrease in distributable income for
the first nine months of 1999 was primarily due to a net deposit of
approximately $1,982,000 into the Trust's Special Cost Escrow Account as
compared to a net release of approximately $1,015,000 for the first nine months
of 1998.
During the first quarter of 1999, the Working Interest Owner of East
Cameron 371/381 informed the Trust that Texaco overpaid royalties to the Trust
in the third and fourth quarters of 1998 in an amount totaling $1,090,367.
Texaco recouped $404,190 of the overpayment from production in the first six
months of 1999 and was to recoup additional royalties of $686,177 in future
periods through future production on this property and West Cameron 643, which
properties are operated by Texaco. Texaco informed the Trust in the third
quarter of 1999 that it is now required to made additional adjustments to
reported financial information on these properties. These adjustments resulted
from Texaco's audit of these Trust properties. This audit was made by Texaco 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, Texaco has informed the Trust
that the loss carryforward projected in the last two Trust quarters should be
adjusted and eliminated, and that Texaco owes the Trust approximately $80,000.
The following summary presents the first nine months of 1998 and 1999 activity
inclusive of these adjustments.
Gas revenues decreased 55% in the first nine months of 1999 as compared to
the first nine months of 1998 primarily due to the adjustments referred to above
on the East Cameron 371/381 property and West Cameron 643 property. In addition,
the gas volumes decreased 53% in the first nine months of 1999 as compared to
the same period in 1998 and the average price received for natural gas decreased
7% from $2.37 per Mcf in the first nine months of 1998 to $2.21 per Mcf in the
first nine months of 1999. Crude oil and condensate revenues decreased
approximately 32% in the first nine months of 1999 in comparison to the same
period in 1998 primarily due to the adjustments referred to above on the East
Cameron 371/381 property and West Cameron 643 property.
The Trust's share of capital expenditures decreased by approximately 63% or
$2,340,260 for the first nine months of 1999 as compared to the same period in
1998 primarily due to the costs associated with drilling the B-7, B-9 and B-12
wells in the first quarter of 1998 and the B-16 well in the second quarter of
1998 on the Eugene Island 339 property. The Trust's share of operating expenses
for the first nine months of 1999 increased by approximately 1% or $10,240 as
compared to the same period in 1998.
For the first nine months of 1999, the Trust had undistributed net loss of
$803,748. 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
9
<PAGE>
respective period, that were applied to an existing loss carryforward. The
undistributed net loss for the first nine months of 1999 was primarily related
to the adjustments referred to above on the East Cameron 371/381 property and
the West Cameron 643 property.
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 compared to a net release of funds from the Special
Cost Escrow Account of approximately $1,015,000 net to the Trust in the first
nine months of 1998. The Special Cost Escrow is set aside for estimated
abandonment costs and future capital expenditures as provided for in the
Conveyance. For additional information relating to the Special Cost Escrow see
"Special Cost Escrow Account" below.
RESERVE FOR FUTURE TRUST EXPENSES
In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. During
1992 and 1993, in anticipation of future periods when the cash received from the
Royalty may not be sufficient for payment of Trust expenses, the reserve for
future Trust general and administrative expenses was increased each quarter by
an amount equal to the difference between $150,000 and the amount of the Trust's
general and administrative expenses for such quarter. In 1994 in anticipation of
future periods when the cash received from the Royalty may not be sufficient for
payment of Trust expenses, the Trust determined, in accordance with the Trust
Agreement, to begin further increasing the Trust's cash reserve each quarter by
an amount equal to the difference between $200,000 and the amount of the Trust's
general and administrative expenses for such quarter. During 1994 and 1995, the
aggregate amount of cash reserved by the Trust was $347,638 and $370,258,
respectively. During 1996, the Trust used cash of $397,845 from the Trust's cash
reserve account to pay the Trust's general and administrative expenses due to
the absence of Royalty income during the first, second and fourth quarters. In
the third quarter of 1996, when Royalty income was received, the Trust reserved
$99,536. Therefore, the net cash used from the Trust's cash reserve account in
1996 was $298,309. During 1997, the aggregate amount of cash reserved by the
Trust was $593,066. 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 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 insufficient royalty income
was received by the Trust. This $25,258 was redeposited to the Trust's cash
reserve account during the third quarter of 1999.
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.
10
<PAGE>
OPERATIONAL REVIEW
THREE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY
THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 crude oil revenues decreased from $2,611,747 in the
third quarter of 1998 to $2,026,917 in the third quarter of 1999, primarily due
to a decrease in crude oil production from 216,332 barrels in the third quarter
of 1998 to 119,891 barrels in the third quarter of 1999. This decrease in crude
oil production was due primarily to the continued natural production decline of
these properties. The decrease in crude oil production was partially offset by
an increase in the average crude oil price from $12.07 per barrel in the third
quarter of 1998 to $16.91 per barrel in the third quarter of 1999. Gas revenues
decreased from $2,034,894 in the third quarter of 1998 to $1,065,787 in the
third quarter of 1999 primarily due a decrease in gas volumes from 896,191 Mcf
in the third quarter of 1998 to 465,704 Mcf in the third quarter of 1999. This
decrease in gas volumes was due primarily to the E-2 well being shut-in the
third quarter of 1999. The decrease in gas volumes was partially offset by an
increase in the average natural gas sales prices from $2.27 per Mcf in the third
quarter of 1998 to $2.38 per Mcf in the same period in 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 93,589 Mcf
have been overtaken by the Working Interest Owner from this property as of July
31, 1999. The Trust's share of this overtake position is approximately 23,397
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 from $1,186,648 in the third
quarter of 1998 to $713,857 in the third quarter of 1999, due primarily to the
costs associated with the drilling of the E-10 well in April 1998 being
recognized in the third quarter of 1998. Operating expenses decreased from
$469,042 in the third quarter of 1998 to $368,451 in the third quarter of 1999
due primarily to the drilling of the E-10 well discussed above. The Working
Interest Owner has advised the Trust that the E-2 sidetrack well drilled in the
third quarter of 1999 has encountered problems and the sidetrack will be started
over.
Eugene Island 339 crude oil revenues decreased from $1,648,827 in the third
quarter of 1998 to $1,180,664 in the third quarter of 1999 due primarily to a
decrease in volumes from 130,009 barrels in the third quarter of 1998 to 76,234
barrels for the same period in 1999. The decrease in volumes was due primarily
to continued natural production decline. The decrease in volumes was partially
offset by an increase in the average crude oil price from $12.68 per barrel in
the third quarter of 1998 to $15.49 per barrel in the third quarter of 1999. Gas
revenues increased from $200,862 to $304,339 due primarily to an increase in gas
volumes from 84,757 Mcf in the third quarter of 1998 to 151,486 Mcf for the same
period in 1999. The increase in volumes was partially offset by a decrease in
the average price received for natural gas from $2.39 per Mcf in the third
quarter of 1998 to $2.22 per Mcf in the third quarter of 1999. The Working
Interest Owner has advised the Trust that there is an overtake imbalance
position of approximately 73,986 Mcf on this property as of July 31, 1999. The
Trust's share of this overtake position is approximately 18,497 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 by $3,659,712 from the third quarter of
1998 to the third quarter of 1999 due primarily to costs incurred in the second
quarter of 1998 which were associated with the drilling activity on the B-7, B-9
and
11
<PAGE>
B-12 wells in the first quarter of 1998 and the B-16 well in the second quarter
of 1998. Operating expenses increased from $131,841 in the third quarter of 1998
to $389,406 in the third quarter of 1999.
West Cameron 643 gas revenues decreased from $3,063,085 in the third
quarter of 1998 to $2,453,002 in the third quarter of 1999 due primarily to a
decrease in gas volumes from 1,342,376 Mcf in the third quarter of 1998 to
954,993 Mcf for the same period in 1999. The decrease in gas volumes was due
primarily to continued natural production decline. This decrease in gas revenue
was partially offset by the upward $251,735 revenue adjustment made in the third
quarter of 1999, as discussed above. In addition, the decrease in revenue was
partially offset by an increase in the average price received for natural gas
from $2.28 per Mcf in the third quarter of 1998 to $2.31 per Mcf for the same
period in 1999. The Working Interest Owner has advised the Trust that the gas
from this property is currently committed under the contract with Texaco Natural
Gas, Inc. pursuant to an agreement for gas to be purchased at a price based on a
weighted average calculation using the Inside FERC's Gas Market Report first of
month indices for Columbia Gulf Transmission Co. -- Louisiana and Tennessee Gas
Pipeline -- Louisiana. Capital expenditures decreased from $740,210 in the third
quarter of 1998 to $673,678 in the third quarter of 1999 due primarily to costs
associated with the drilling of the A-10 sidetrack well and the workover on the
A-17 well in the second quarter of 1998 being recognized in the third quarter of
1998. Operating expenses decreased from $728,556 in the third quarter of 1998 to
$275,272 for the same period in 1999 due primarily to the A-17 well workover
discussed above.
East Cameron 371/381 started production in May 1998. Gas revenues on this
property decreased from $3,358,433 in the third quarter of 1998 to $1,002,262 in
the third quarter of 1999 due primarily to a decrease in gas volumes from
1,494,613 Mcf in the third quarter of 1998 to 235,563 Mcf in the third quarter
of 1999. The decrease in gas volumes was due primarily to the overpayments made
in 1998 on this property, as discussed earlier. The decrease in revenues and
volumes was partially offset by an increase in the average price received for
natural gas from $2.25 in the third quarter of 1998 to $2.36 in the third
quarter of 1999 and an upward $69,240 revenue adjustment made in the third
quarter of 1999, as discussed above. The gas from East Cameron 371/381 is
currently committed to TNG at a calculated price based on an average calculation
using the Inside FERC's Gas Market Report first of the month indices for
Columbia Gulf Transmission Co. -- Louisiana, Henry Hub, Koch Gateway Pipeline
Co. -- South Louisiana, and Southern Natural Gas Co. -- Louisiana. Crude oil
revenues increased from $156,511 in the third quarter of 1998 to $932,039 in the
third quarter of 1999, due primarily to an upward revenue adjustment of $734,161
made in the third quarter of 1999, as discussed above, and an increase in the
average crude oil price from $12.87 per barrel in the third quarter of 1998 to
$17.54 per barrel in the third quarter of 1999. The increase in revenues and
average crude oil price was partially offset by a decrease in crude oil
production from 12,159 barrels in the third quarter of 1998 to 11,281 barrels in
the third quarter of 1999. Capital expenditures increased from $933,892 in the
third quarter of 1998 to $1,766,882 in the third quarter of 1999 due primarily
to the adjustment made to this property in the third quarter of 1999 by the
Working Interest Owner as discussed above. Operating expenses decreased $301,649
in the third quarter of 1999 as compared to the same period in 1998 due
primarily to a downward adjustment of $261,718 made in the third quarter of
1999, as discussed above. The Working Interest Owner has advised the Trust that
there are plans to drill the A-6 and A-7 wells in early 2000 at an estimated
cost of approximately $13 million ($3.25 million net to the Trust).
12
<PAGE>
NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY
THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 crude oil revenues decreased from $10,732,426 in the
first nine months of 1998 to $5,479,475 in the first nine months of 1999,
primarily due to a decrease in crude oil production from 717,283 barrels in the
first nine months of 1998 to 418,940 barrels in the first nine months of 1999.
The decrease in crude oil production was due primarily to continued natural
production decline on these properties and due to the processing structure being
shut-in for 7 days in April 1999 due to mechanical problems experienced in the
production facilities. In addition, there was a decrease in the average crude
oil price from $14.96 per barrel in the first nine months of 1998 to $13.08 per
barrel for the same period in 1999. Gas revenues decreased from $3,825,338 in
the first nine months of 1998 to $2,682,334 in the first nine months of 1999
primarily due to a decrease in gas volumes from 1,628,003 Mcf in the first nine
months of 1998 to 1,370,803 Mcf in the first nine months of 1999. This decrease
in gas volumes was due primarily to the E-2 well being shut-in in the third
quarter of 1999. In addition, there was a decrease in the natural gas sales
price from $2.40 per Mcf in the first nine months of 1998 to $2.04 per Mcf in
the first nine months of 1999. Capital expenditures decreased from $1,406,654 in
the first nine months of 1998 to $753,020 in the first nine months of 1999 due
primarily to the costs associated with drilling of the E-10 well in April 1998
being recognized in the third quarter of 1998. Operating expenses decreased from
$1,200,634 in the first nine months of 1998 to $1,091,623 for the same period in
1999.
Eugene Island 339 crude oil revenues decreased from $3,752,907 in the first
nine months of 1998 to $3,231,124 in the first nine months of 1999, due
primarily to a decrease in volumes from 282,487 barrels in the first nine months
of 1998 to 268,178 barrels in the first nine months of 1999. In addition there
was a decrease in the average crude oil price from $13.29 per barrel in the
first nine months of 1998 to $12.04 per barrel in the first nine months of 1999.
Gas revenues increased from $829,313 in the first nine months of 1998 to
$878,642 in the first nine months of 1999 due primarily to an increase in gas
volumes from 344,702 Mcf for the first nine months of 1998 to 457,723 Mcf for
the same period in 1999. This increase in revenues was partially offset by a
decrease in the average price received for natural gas from $2.55 per Mcf in the
first nine months of 1998 to $2.12 per Mcf in the first nine months of 1999.
Capital expenditures decreased $8,718,955 from the first nine months of 1998 to
the first nine months of 1999 due primarily to drilling activity on the B-7, B-9
and B-12 wells in the first quarter of 1998. Operating expenses increased from
$397,727 in the first nine months of 1998 to $1,074,325 in the first nine months
of 1999 due primarily to an adjustment to properly reflect costs in the first
quarter of 1998.
West Cameron 643 gas revenues decreased from $6,754,309 in the first nine
months of 1998 to $4,849,483 in the first nine months of 1999 due primarily to a
decrease in gas volumes from 2,824,919 Mcf in the first nine months of 1998 to
2,198,416 Mcf for the same period of 1999. The decrease in gas volumes was due
primarily to the continued natural production decline. In addition, there was a
decrease in the average price received for natural gas from $2.39 per Mcf in the
first nine months of 1998 to $2.20 per Mcf for the same period in 1999. Capital
expenditures increased from $1,245,051 in the first nine months of 1998 to
$1,270,627 in the first nine months of 1999. Operating expenses decreased from
$1,221,427 in the first nine months of 1998 to $777,880 for the same period in
1999 due primarily to costs associated with the A-17 well workover being
recognized in the second quarter of 1998.
East Cameron 371/381 started production in May 1998. Gas revenues on this
property decreased from $3,358,433 in the first nine months of 1998 to
($2,037,817) in the first nine months of 1999 due primarily to a decrease in gas
volumes from 1,494,613 Mcf in the first nine months of 1998 to (1,244,067) Mcf
in the first nine months of 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
13
<PAGE>
$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 1999 and was to 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. Crude oil revenues increased from $156,511 in the first nine
months of 1998 to $907,780 in the first nine months of 1999 due primarily to an
upward adjustment of $734,161 made in the third quarter of 1999 as discussed
above. Capital expenditures increased from $2,997,807 in the first nine months
of 1998 to $3,204,674 in the first nine months of 1999 due primarily to a
$1,514,771 upward adjustment made in the third quarter of 1999 as discussed
above. In addition, there was a prior period adjustment for the A-5 well
drilling costs in the second quarter of 1999. Operating expenses decreased from
$253,410 in the first nine months of 1998 to $171,637 in the first nine months
of 1999 due primarily to a $261,718 downward adjustment made in the third
quarter of 1999 as discussed above.
FUTURE NET REVENUES AND TERMINATION OF THE TRUST
Based on a reserve study provided to the Trust by DeGolyer and MacNaughton,
independent petroleum engineers, it was estimated that as of October 31, 1998
future net revenues attributable to the Trust's royalty interests approximated
$16.3 million. Such reserve study also indicates that approximately 79% 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 1998 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
14
<PAGE>
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 1998, there was a net release
of funds from the Special Cost Escrow Account. The Trust's share of the funds
released was approximately $1,015,000. The release was primarily a result of a
decrease in the estimates of projected capital expenditures of the Royalty
Properties. 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 deposit was primarily a result of an increase
in the estimate of projected capital expenditures of 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.
As of September 30, 1999, approximately $5,888,000 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.
15
<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
SEPTEMBER 30,(1)
------------------------------
1999 1998(3)
-------------- --------------
Crude oil and condensate (bbls)......... 212,200 362,143
Natural gas and gas products (Mcf)...... 1,953,263 3,960,146
Crude oil and condensate average price,
per bbl............................... $ 16.44 $ 12.33
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.31 $ 2.27
Crude oil and condensate revenues....... $ 4,420,802 $ 4,463,987
Natural gas and gas products revenues... 5,148,989 8,985,994
Production expenses..................... (1,216,448) (2,062,538)
Capital expenditures.................... (3,124,133) (6,598,502)
Undistributed Net Loss (Income)(2)...... (87,125) 25,966
(Provision for) Refund of escrowed
special costs......................... (2,390,041) (1,229,739)
-------------- --------------
NET PROCEEDS............................ 2,752,044 3,585,168
Royalty interest........................ x25% x25%
-------------- --------------
Partnership share....................... 688,011 896,292
Trust interest.......................... x99.99% x99.99%
-------------- --------------
Trust share............................. $ 687,942 $ 896,202
============== ==============
- ------------
(1) The amounts for the three months ended September 30, 1999 and 1998 represent
actual production for the periods May 1999 through July 1999, and May 1998
through July 1998, 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, 1999, the loss carryforward
was $1,278,268 ($319,567 net to the Trust).
(3) During the first quarter of 1999, Texaco, the Working Interest Owner of East
Cameron 371/381 informed the Trust that it 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, Texaco overpaid the Trust royalties totaling $1,090,367. Texaco
recouped $404,190 of the overpayment from production in the first six months
of 1999 and was to recoup additional royalties of $686,177 in future periods
through future production on this property and West Cameron 643, which
properties are operated by Texaco. Texaco has informed the Trust in the
third quarter of 1999 that it is now required to make additional adjustments
to reported financial information on these properties. These adjustments
resulted from Texaco's audit of these Trust properties. This audit was made
by Texaco 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
16
<PAGE>
well as revenues attributable to differences in pricing formulas, that
should have been paid to the Trust. After netting these findings, Texaco has
informed the Trust that the loss carryforward projected in the last two
Trust quarters should be adjusted and eliminated, and that Texaco owes the
Trust approximately $80,000.
ROYALTY PROPERTIES
NINE MONTHS ENDED
SEPTEMBER 30,(1)
------------------------------
1999(3) 1998(3)
-------------- --------------
Crude oil and condensate (bbls)......... 711,100 1,024,928
Natural gas and gas products (Mcf)...... 3,182,162 6,785,220
Crude oil and condensate average price,
per bbl............................... $ 14.09 $ 14.48
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.21 $ 2.37
Crude oil and condensate revenues....... $ 10,021,350 $ 14,844,876
Natural gas and gas products revenues... 7,169,251 15,978,606
Production expenses..................... (3,533,259) (4,014,481)
Capital expenditures.................... (5,610,497) (14,971,535)
Undistributed Net Loss (Income)(2)...... 3,214,993 (110,472)
(Provision for) Refund of escrowed
special costs......................... (7,927,918) 4,060,942
-------------- --------------
NET PROCEEDS............................ 3,333,920 15,787,936
Royalty interest........................ x25% x25%
-------------- --------------
Partnership share....................... 833,480 3,946,984
Trust interest.......................... x99.99% x99.99%
-------------- --------------
Trust share............................. $ 833,397 $ 3,946,589
============== ==============
- ------------
(1) The amounts for the three months ended September 30, 1999 and 1998 represent
actual production for the periods November 1998 through July 1999, and
November 1997 through July 1998, 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, 1999, the loss carryforward
was $1,278,268 ($319,567 net to the Trust).
(3) During the first quarter of 1999, Texaco, the Working Interest Owner of East
Cameron 371/381 informed the Trust that it 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, Texaco overpaid the Trust royalties totaling $1,090,367. Texaco
recouped $404,190 of the overpayment from production in the first six months
of 1999 and was to recoup additional royalties of $686,177 in future periods
through future production on this property and West Cameron 643, which
properties are operated by Texaco. Texaco has informed the Trust in the
third quarter of 1999 that it is now required to make additional adjustments
to reported financial information on these properties. These adjustments
resulted from Texaco's audit of these Trust properties. This audit was made
by Texaco 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,
Texaco has informed the Trust that the loss carryforward projected in the
last two Trust quarters should be adjusted and eliminated, and that Texaco
owes the Trust approximately $80,000.
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
------------- -------
<C> <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 third quarter of 1999.
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: Chase Bank of Texas, National
Association, Corporate Trustee
By: /s/ PETE FOSTER
Pete Foster
SENIOR VICE PRESIDENT
AND TRUST OFFICER
Date: November 15, 1999
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
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENT OF ASSETS, LIABILITIES, AND TRUST CORPUS AS OF SEP-30-1999 AND THE
STATEMENT OF DISTRIBUTABLE INCOME FOR THE NINE MONTHS ENDED SEP-30-1999 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 1,992,216
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,992,216
<PP&E> 28,267,655
<DEPRECIATION> 27,845,989
<TOTAL-ASSETS> 2,413,882
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 421,666
<TOTAL-LIABILITY-AND-EQUITY> 2,413,882
<SALES> 0
<TOTAL-REVENUES> 878,758
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 215,192
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 663,566
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 663,566
<EPS-BASIC> .139
<EPS-DILUTED> .139
</TABLE>
