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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 JUNE 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
________________________
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 August 4, 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
JUNE 30, DECEMBER 31,
2000 1999
---------- ------------
(UNAUDITED)
ASSETS
Cash and cash equivalents............ $2,393,459 $3,456,123
Net overriding royalty interest in
producing oil and gas properties,
net of accumulated amortization of
$27,938,439 and $27,899,887,
respectively....................... 329,216 367,768
---------- ----------
Total assets......................... $2,702,675 $3,823,891
========== ==========
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit
holders............................ $1,255,975 $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)....................... 329,216 367,768
---------- ----------
Total liabilities and Trust corpus... $2,702,675 $3,823,891
========== ==========
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------------- ---------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Royalty income....................... $1,323,086 $ 56,759 $2,574,267 $ 145,455
Interest income...................... 16,587 13,671 34,604 29,503
---------- ---------- ---------- ----------
1,339,673 70,430 2,608,871 174,958
Decrease in reserve for future Trust
expenses........................... 0 25,258 266,759 7,050
General and administrative
expenses........................... (83,698) (95,688) (161,306) (126,415)
---------- ---------- ---------- ----------
Distributable income................. $1,255,975 $ -- $2,714,324 $ 55,593
========== ========== ========== ==========
Distributions per Unit (4,751,510
Units)............................. $ .264331 $ .000000 $ .571254 $ .011700
========== ========== ========== ==========
</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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------- ----------------------------
2000 1999 2000 1999
----------- ---------- ---------- -----------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period.... $ 348,217 $ 438,889 $ 367,768 $ 442,621
Distributable income................. 1,252,236 -- 2,710,585 55,593
Distribution payable to Unit
holders............................ (1,252,236 -- (2,710,585) (55,593)
Amortization of net overriding
royalty interest................... (19,001) (1,746) (38,552) (5,478)
----------- ---------- ---------- -----------
Trust corpus, end of period.......... $ 329,216 $ 437,143 $ 329,216 $ 437,143
=========== ========== ========== ===========
</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, in general, will continue to
operate as if the above-described sales of the Royalty Properties had not
occurred.
Unless the context in which such terms are used indicates otherwise, in
these Notes the terms "Working Interest Owner" and "Working Interest Owners'
generally refer to the owner or owners of the Royalty Properties (Exploration I
through October 31, 1986; Tenneco for periods from October 31, 1986 until
November 18, 1988; Chevron with respect to all Royalty Properties for periods
from November 18, 1988 until October 30, 1992, and with respect to all Royalty
Properties except East Cameron 354, Eugene Island 348, Eugene Island 367 and
Eugene Island 208 for periods from October 30, 1992 until December 1, 1994, and
with respect to the same properties except West Cameron 643 and East Cameron
371/381 thereafter; PennzEnergy with respect to East Cameron 354, Eugene Island
348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992
until October 1, 1995, and with respect to Eugene Island 348 and Eugene Island
208 until January 1, 2000; Texaco with respect to West Cameron 643 and East
Cameron 371/381 for periods beginning on or after December 1, 1994; SONAT with
respect to East Cameron 354 for periods beginning on or after October 1, 1995;
and Amoco with respect to Eugene Island 367 for periods beginning on or after
October 1, 1995; and Amerada with respect to East Cameron 354 for periods
beginning on or after January 1, 1998; and Devon with respect to Eugene Island
348 and Eugene Island 208 for periods beginning on or after January 1, 2000).
NOTE 2 -- BASIS OF ACCOUNTING
The accompanying unaudited financial information has been prepared by 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 which are, in the opinion of
the Trustees, necessary for a fair presentation of the results for the interim
periods presented. The financial information should be read in conjunction with
the financial statements and notes thereto included in the Trust's Annual Report
on Form 10-K for the year ended December 31, 1999.
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income is recorded when received by the Corporate Trustee
on the last business day of each calendar quarter; and
(b) Trust general and administrative expenses are recorded when paid,
except for the cash reserved for future general and
administrative expenses, as discussed in Note 6.
This manner of reporting income and expenses is considered to be the most
meaningful because the quarterly distributions to Unit holders are based on net
cash receipts received from the Working Interest Owners. The financial
statements of the Trust differ from financial statements prepared in accordance
with
4
<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 Royal
Properties. As provided in the Conveyance, the amount of funds to be reserved is
determined based on certain factors, including estimates of aggregate future
production costs, aggregate future Special Costs,
5
<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 six 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 $1,384,500. The deposit was primarily a result of an increase in
the Working Interest Owners" current estimate of projected capital expenditures
on the Royalty Properties. In 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 six 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 $909,500. The deposit was primarily a
result of an increase in the Working Interest Owners" current estimate of
projected capital expenditures of the Royalty Properties. As of June 30, 2000,
approximately $6,403,000 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 $491,500 has been recovered from the Trust by this Working
Interest Owner through the second 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 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 JUNE 30, 2000 AND 1999
Distributions to Unit holders for the three months ended June 30, 2000
amounted to $1,255,975 or $.264331 per Unit as compared to no distribution to
Unit holders for the same period in 1999. The increase in distributable income
for the second quarter of 2000 was primarily due to increased oil and gas
prices, offset by production volume declines, as described below.
Gas revenues decreased approximately 12% or $391,075 in the second quarter
of 2000 compared to the second quarter of 1999 primarily due to a 41% decrease
in gas volumes in the second quarter of 2000 compared to the second 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
loading up in the second quarter of 2000. Both wells are candidates for
workovers in 2000. The decrease in gas volumes was partially offset by a 45%
increase in the average price received for natural gas from $1.87 per thousand
cubic feet of gas ("Mcf") in the second quarter of 1999 to $2.71 per Mcf in the
second quarter of 2000.
Crude oil and condensate revenues increased approximately 107% or
$3,251,907 in the second quarter of 2000 as compared to the same period in 1999
primarily due to a 126% increase in the average price received from $12.41 per
barrel in the second quarter of 1999 to $27.99 per barrel in the second quarter
of 2000. The increase in average price was partially offset by an 8% decrease in
crude oil and condensate volumes from the 1999 second quarter to the 2000 second
quarter.
The Trust's share of capital expenditures decreased approximately 91% or
$372,773 in the second quarter of 2000 as compared to the same period in 1999
primarily due to the A-5 well drilling costs being recognized in the second
quarter of 1999 on the East Cameron 371/381 property. The Trust's share of
operating expenses decreased by approximately 19% or $60,906 in the second
quarter of 2000 as compared to the same period in 1999 due primarily to the
workover on the A-1 well on the East Cameron 371/381 property in the second
quarter of 1999.
For the second quarter of 2000, the Trust had undistributed net income of
$22,190. Undistributed net income represents positive Net Proceeds, generated
during the respective period, that were applied to an 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 second quarter
of 2000 was primarily related to the loss carryforward referred to above on the
Eugene Island 348 property.
In the second quarter of 2000, there was a net deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $644,587, compared to a net deposit of funds into the Special Cost
Escrow Account of $923,500 net to the Trust in the second 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.
8
<PAGE>
SIX MONTHS ENDED JUNE 30, 2000 AND 1999
Distributions to Unit holders for the six months ended June 30, 2000
amounted to $2,714,324 or $.571254 per Unit as compared to $55,593 or $.011700
per Unit for the same period in 1999. The increase in distributable income for
the first six 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 following summary presents the first six months of
1999 activity inclusive of this one-time adjustment.
Gas revenues increased 203% or $4,096,888 in the first six months of 2000
as compared to the first six months of 1999 primarily due to a 51% increase in
the average price received for natural gas from $1.73 per Mcf in the first six
months of 1999 to $2.62 per Mcf in the first six months of 2000. In addition,
there was a 92% increase in gas volumes, which increase was primarily
attributable to the one-time downward adjustments referred to above on the East
Cameron 371/381 property in 1999.
Crude oil and condensate revenues increased approximately 106% or
$5,942,734 in the first six months of 2000 as compared to the same period in
1999 primarily due to a 137% increase in the average price received from $11.23
per barrel for the six months ended June 30, 1999 to $26.66 per barrel for the
six months ended June 30, 2000. The increase in the average price for crude oil
and condensate was partially offset by a 13% decrease in the crude oil and
condensate volumes.
The Trust's share of capital expenditures decreased by approximately 55% or
$344,161 for the six months ended June 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. The Trust's share
of operating expenses increased by approximately 5% or $25,904 for the six
months ended June 30, 2000 as compared to the same period in 1999.
For the first six months of 2000, the Trust had undistributed net loss of
$44,877. The undistributed net loss for the first six months of 2000 was
primarily related to the one-time adjustment referred to above on the East
Cameron 371/381 property.
In the first six 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 $909,500 compared to a net deposit of funds into the Special Cost
Escrow Account of approximately $1,384,500 net to the Trust in the first six
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
9
<PAGE>
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 JUNE 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 $1,708,170 in the
second quarter of 1999 to $4,334,579 in the second quarter of 2000, primarily
due to an increase in the average crude oil price from $12.69 per barrel in the
second quarter of 1999 to $28.13 per barrel in second quarter of 2000. In
addition, there was an increase in crude oil production from 134,624 barrels in
the second quarter of 1999 to 154,106 barrels in the second quarter of 2000.
This increase in crude oil production was due primarily to the processing
structure being shut-in for 7 days in April 1999 due to mechanical problems
experienced in the production facilities. Gas revenues decreased from $1,084,608
in the second quarter of 1999 to $688,967 in the second quarter of 2000
primarily due to a decrease in gas volumes from 620,378 Mcf in the second
quarter of 1999 to 253,375 Mcf in the second quarter of 2000. This decrease in
gas volumes was primarily the result of lower production on the E-10 well, which
was reworked in the second quarter of 1999, and the continued natural gas
production decline on the properties. The decrease in gas volumes was partially
offset by an increase in the average natural gas sales prices from $1.82 per Mcf
in the second quarter of 1999 to $2.76 per Mcf in 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 88,659 Mcf have been overtaken by the Working Interest Owner from
this property as of April 30, 2000. The Trust's share of this overtake position
is approximately 22,165 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 $23,172
in the second quarter of 1999 to $4,494 in the second quarter of 2000. Operating
expenses increased from $364,888 in the second quarter of 1999 to $442,576 for
the same period in 2000. The Working Interest Owner has advised the Trust that
it plans to drill an E-8 sidetrack well in August 2000 at an approximate cost of
$1.2 million ($300,000 net to the Trust).
10
<PAGE>
Eugene Island 339 crude oil revenues increased from $1,076,721 in the
second quarter of 1999 to $1,551,522 for the same period in 2000 primarily due
to an increase in the average crude oil price from $11.73 per barrel in the
second quarter of 1999 to $27.29 per barrel in the second quarter of 2000. The
increase in the average crude oil price was partially offset by a decrease in
the volumes from 91,796 barrels in the second quarter of 1999 to 56,857 barrels
in the second quarter of 2000. The decrease in volumes was due primarily to the
wells being shut-in due to the compressor being down for 18 days in the second
quarter of 2000. Gas revenues decreased from $389,612 in the second quarter of
1999 to $275,290 in the second quarter of 2000 due primarily to a decrease in
gas volumes from 208,035 Mcf in the second quarter of 1999 to 94,240 Mcf in the
second quarter of 2000. The decrease in gas volumes was due primarily to a
positive volume adjustment made in the second quarter of 1999 and the compressor
being down for 18 days in the second quarter of 2000. The decrease in volumes
was partially offset by an increase in the average price received for natural
gas from $2.07 per Mcf in the second quarter of 1999 to $2.99 per Mcf in the
same period in 2000. The Working Interest Owner has advised the Trust that there
is an overtake imbalance position of approximately 6,037 Mcf on this property as
of April 30, 2000. The Trust's share of this overtake position is approximately
1,509 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 $398,977 from the second quarter of
1999 as compared to the second quarter of 2000. Operating expenses decreased by
$2,023 from the second quarter of 1999 to the second quarter of 2000. The
Working Interest Owner has advised the Trust that it plans to drill a
delineation well on this property during the second and third quarters of 2000
at an approximate cost of $2.8 million ($700,000 net to the Trust).
West Cameron 643 gas revenues increased from $1,111,532 in the second
quarter of 1999 to $1,131,989 in the second quarter of 2000 primarily due to an
increase in the average price received for natural gas from $1.85 per Mcf in the
second quarter of 1999 to $2.64 per Mcf in the second quarter of 2000. The
increase in the average price received for natural gas was partially offset by a
decrease in gas volumes from 602,023 Mcf in the second quarter of 1999 to
429,286 Mcf for the same period in 2000. The decrease in gas volumes was due
primarily to increased water production on the A-10 well and the A-14 well
loading up in the second quarter of 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 15,261 Mcf have been overtaken by the
Working Interest Owner from this property as of April 30, 2000. The Trust's
share of this overtake position is approximately 3,815 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 $312,962 in the second quarter of 1999 to $222,834 for the same period in
2000. Capital expenditures decreased by $564,285 in the second quarter of 1999
as compared to the same period in 2000, primarily due to costs associated with
bringing the B9-D well online in the second quarter of 1999.
East Cameron 371/381 crude oil revenues increased from $169,869 in the
second quarter of 1999 to $258,687 in the second quarter of 2000 primarily due
to an increase in the average crude oil price from $13.50 per barrel in the
second quarter of 1999 to $29.30 per barrel in the second quarter of 2000. The
11
<PAGE>
increase in the average crude oil price was partially offset by a decrease in
crude oil production from 12,582 barrels in the second quarter of 1999 to 8,829
barrels in the same period in 2000. This decrease in production was primarily
due to declining production on the A-1, A-2 and A-3 wells in second quarter of
2000. Gas revenues increased from $435,638 in the second quarter of 1999 to
$525,601 in the second quarter of 2000 primarily due to an increase in the
average price received for natural gas from $1.90 per Mcf in the second quarter
of 1999 to $2.69 per Mcf in the second quarter of 2000. The increase in the
average price received was partially offset by a decrease in gas volumes from
228,885 Mcf in the second quarter of 1999 to 197,423 Mcf for the same period in
2000. The decrease in volumes was primarily due to declining production on the
A-1, A-2 and A-3 wells in the second quarter of 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 $1,257,398 in the second quarter of
2000 as compared to the same period in 1999 primarily due to a prior period
adjustment for the A-5 well drilling costs in the second quarter of 1999.
Operating expenses decreased from $227,321 in the second quarter of 1999 to
$7,493 in the second quarter of 2000 primarily due to costs associated with the
A-1 well workover in the second quarter of 1999 and a prior period adjustment
for the A-5 well drilling costs. Operating expenses increased from $31,827 in
the first quarter of 1999 to $34,254 in the first quarter of 2000.
SIX MONTHS ENDED JUNE 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 $3,452,557 in the
first six months of 1999 to $7,460,386 in the first six months of 2000,
primarily due to an increase in the average crude oil price from $11.54 per
barrel in the first six months of 1999 to $26.92 per barrel for the same period
in 2000. The increase in the average crude oil price was partially offset by a
decrease in crude oil production from 299,049 barrels in the first six months of
1999 to 277,143 barrels in the first six months of 2000. The decrease in crude
oil production was primarily due to the continued natural production decline of
these properties. Gas revenues decreased from $1,616,547 in the first six months
of 1999 to $1,455,259 in the first six months of 2000 primarily due to a
decrease in gas volumes from 905,099 Mcf in the first six months of 1999 to
563,722 Mcf for the same period in 2000. The decrease in gas volumes was
primarily the result of less production on the E-10 well which was reworked in
the second quarter of 1999 and the continued natural production decline on the
properties. The decrease in gas volumes was partially offset by an increase in
the natural gas sales price from $1.86 per Mcf in the first six months of 1999
to $2.63 per Mcf in the same period in 2000. Capital expenditures increased from
$39,162 in the first six months of 1999 to $164,623 in the same period of 2000
primarily due to sumpwork on the C well and reservoir stimulation on the C and E
wells in the first quarter of 2000. Operating expenses increased from $723,171
for the first six months of 1999 to $896,640 for the first six months of 2000
due to increased expenditures.
Eugene Island 339 crude oil revenues increased from $2,050,460 in the first
six months of 1999 to $3,237,274 for the same period in 2000 primarily due to an
increase in the average crude oil price from $10.68 per barrel in the first six
months of 1999 to $25.70 per barrel in the first six months of 2000. The
increase in the average crude oil price was partially offset by a decrease in
volumes from 191,944 barrels in the first six months of 1999 to 125,975 barrels
for the same period in 2000. The decrease in volumes was primarily due to the
wells being shut-in due to the compressor being down for 18 days in the second
quarter of 2000. Gas revenues decreased from $574,303 in the first six months of
1999 to $540,995 in the first six months of 2000 primarily due to a decrease in
gas volumes from 306,237 Mcf in the first six months of 1999 to 206,552 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 and the compressor
being down for 18 days in the second quarter of 2000. The decrease in gas
volumes was partially offset by an increase in the
12
<PAGE>
average price received for natural gas from $2.07 per Mcf in the first six
months of 1999 to $2.66 per Mcf in the first six months of 2000. Operating
expenses increased from $684,919 for the six months of 1999 to $698,281 for the
first six months of 2000. Capital expenditures increased from $327,641 in the
first six months of 1999 to $669,105 in the first six months of 2000 due
primarily to the drilling of the B-18 sidetrack well and improvements on the
platform B A614 facilities in the first six months of 2000.
West Cameron 643 gas revenues increased from $2,396,481 in the first six
months of 1999 to $2,460,241 in the first six months of 2000 primarily due to an
increase in the average price received for natural gas from $1.93 per Mcf in the
first six months of 1999 to $2.61 per Mcf for the same period in 2000. The
increase in the average price received for natural gas was partially offset by a
decrease in gas volumes from 1,243,423 Mcf in the first six months of 1999 to
943,183 Mcf for the same period in 2000. The decrease in gas volumes was due
primarily to the A-10 well being shut down in the first quarter of 2000 for
maintenance work. Operating expenses increased from $502,608 for the first six
months of 1999 to $649,031 for the first six months of 2000 due primarily to
maintenance work on the B well in the first quarter of 2000. Capital
expenditures decreased from $596,949 in the first six months of 1999 to $91,816
in the first six months of 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 increased $559,100 in the first six
months of 2000 as compared to in the first six months of 1999 primarily due to
an increase in the average crude oil price from $13.22 per barrel in the first
six months of 1999 to $27.63 per barrel in the first six months of 2000. In
addition, there was an increase in oil production of 21,003 barrels in the first
six months of 2000 as compared to the same period in 1999 due to a downward
adjustment in the first quarter of 1999. Gas revenues decreased from $1,232,477
in the first six months of 1999 to $1,088,473 in the first six months of 2000
primarily due to a decrease in gas production from 591,532 Mcf in the first six
months of 1999 to 220,018 Mcf for the same period in 2000. 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 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 decrease in gas
volumes was partially offset by an increase in the average price received for
natural gas from $2.08 per Mcf in the first six months of 1999 to $2.62 per Mcf
in the first six months of 2000. Capital expenditures decreased from $1,437,792
in the first six months of 1999 to $164,251 in the first six months of 2000 due
primarily to a prior period adjustment for the A-5 well drilling costs in the
second quarter of 1999. Operating expenses decreased from $259,148 in the first
six months of 1999 to $41,747 in the first six months of 2000 due primarily to
costs associated with the A-1 well workover in the second quarter of 1999 and a
prior period adjustment for the A-5 well drilling costs.
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
13
<PAGE>
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 six 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 $1,384,500. The deposit
was primarily a result of an increase in the Working Interest Owners" current
estimate of projected capital expenditures on the Royalty Properties. In
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 six 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 $909,500. The deposit was primarily a result of an increase in the
Working Interest Owners" current estimate of projected capital expenditures of
the Royalty Properties. As of June 30, 2000, approximately $6,403,000 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.
14
<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
JUNE 30,(1)
-----------------------------
2000 1999(3)
----------- -----------
Crude oil and condensate (bbls)......... 224,680 244,729
Natural gas and gas products (Mcf)...... 1,067,761 1,796,859
Crude oil and condensate average price,
per bbl............................... $ 27.99 $ 12.41
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.71 $ 1.87
Crude oil and condensate revenues....... $ 6,288,297 $ 3,036,390
Natural gas and gas products revenues... 2,874,320 3,265,395
Production expenses..................... (1,060,600) (1,379,586)
Capital expenditures.................... (142,037) (1,633,128)
Undistributed Net Loss (Income)(2)...... (88,761) 631,939
(Provision for) Refund of escrowed
special costs......................... (2,578,347) (3,693,950)
----------- -----------
NET PROCEEDS............................ 5,292,872 227,060
Royalty interest........................ x25% x25%
----------- -----------
Partnership share....................... 1,323,218 56,765
Trust interest.......................... x99.99% x99.99%
----------- -----------
Trust share............................. $ 1,323,086 $ 56,759
=========== ===========
------------
(1) The amounts for the three months ended June 30, 2000 and 1999 represent
actual production for the periods February 2000 through April 2000, and
February 1999 through April 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 June 30, 2000, the loss carryforward was
$1,017,752 ($254,438 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.
15
<PAGE>
ROYALTY PROPERTIES
SIX MONTHS ENDED
JUNE 30,(1)
-----------------------------
2000 1999(3)
----------- -----------
Crude oil and condensate (bbls)......... 433,026 498,900
Natural gas and gas products (Mcf)...... 2,354,902 1,228,899
Crude oil and condensate average price,
per bbl............................... $ 26.66 $ 11.23
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.62 $ 1.73
Crude oil and condensate revenues....... $11,543,282 $ 5,600,548
Natural gas and gas products revenues... 6,117,150 2,020,262
Production expenses..................... (2,434,845) (2,316,807)
Capital expenditures.................... (1,109,721) (2,486,364)
Undistributed Net Loss (Income)(2)...... (179,507) 3,302,118
(Provision for) Refund of escrowed
special costs......................... (3,638,263) (5,537,877)
----------- -----------
NET PROCEEDS............................ 10,298,096 581,880
Royalty interest........................ x25% x25%
----------- -----------
Partnership share....................... 2,574,524 145,470
Trust interest.......................... x99.99% x99.99%
----------- -----------
Trust share............................. $ 2,574,267 $ 145,455
=========== ===========
------------
(1) The amounts for the six months ended June 30, 2000 and 1999 represent actual
production for the periods November 1999 through April 2000, and November
1998 through April 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 June 30, 2000, the loss carryforward was
$1,017,752 ($234,438 net to the Trust).
(3) During the first quarter of 1999, the Working Interest Owner of East Cameron
371/381 informed the Trust that the Working Interest Owner overpaid East
Cameron 371/381 royalties, related primarily to natural gas production, to
the Trust in the third and fourth quarters of 1998. The total gas revenue
and volume reported to the Trust was $5,696,741 ($1,424,185 net to the
Trust) and 2,761,549 Mcf (690,387 Mcf net to the Trust), respectively. The
amount that should have been reported to the Trust for gas revenue and
volume was $1,424,185 ($356,046 net to the Trust) and 690,387 Mcf (172,597
Mcf net to the Trust), respectively. As a result of these miscalculations
and other minor adjustments, the Working Interest Owner overpaid the Trust
royalties totaling $1,090,367. The Working Interest Owner of East Cameron
371/381 recouped $404,190 of the overpayment from production in the first
quarter of 1999 and will recoup additional royalties of $686,177 in future
periods through future production on this property and West Cameron 643,
which properties are operated by this Working Interest Owner.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Reference is made to Item 1 of this Form 10-Q.
16
<PAGE>
PART II -- OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(A) EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.)
<TABLE>
<CAPTION>
SEC FILE OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------- -------
<S> <C> <C> <C> <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 second quarter of 2000.
17
<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: August 10, 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.
18
