- -------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934 for the
quarterly period ended September 30, 1995
[ ] Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934 for the
transition period from __________ to __________
Commission File No. 0-6910
TEL OFFSHORE TRUST
(Exact Name of Registrant as Specified in its Charter)
Texas 76-6004064
(State of Incorporation (I.R.S. Employer
or Organization) Identification No.)
Texas Commerce Bank
National Association
Corporate Trust Division
712 Main Street
Houston, Texas 77002
(Address of Principal (Zip Code)
Executive Offices)
(713) 216-5712
(Registrant's Telephone Number, Including Area Code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. 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, 1995 -- 4,751,510 Units of Beneficial Interest in TEL
Offshore Trust.
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<PAGE>
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
TEL OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ --------------------------
1995 1994 1995 1994
--------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Royalty income ................... $ 468,689 $ 696,241 $ 1,109,052 $ 2,979,118
Interest income .................. 8,406 4,153 22,110 10,162
--------- ----------- ----------- -----------
477,095 700,394 1,131,162 2,989,280
Increase in expense reserve ...... (128,169) (100,628) (289,525) (237,739)
General and administrative expense (71,831) (99,372) (310,475) (362,261)
--------- ----------- ----------- -----------
Distributable income ............. $ 277,095 $ 500,394 $ 531,162 $ 2,389,280
========= =========== =========== ===========
Distributions per Unit
(4,751,510 Units) ........... $ .058317 $ .105312 $ .111787 $ .502845
========= =========== =========== ===========
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
September 30, December 31,
1995 1994
---------- ----------
(Unaudited)
<S> <C> <C>
ASSETS
Cash and short-term investments .................................. $1,374,294 $1,069,217
Net overriding royalty interests in oil and gas properties (net of
accumulated amortization of $27,136,316 and $26,924,180,
respectively) ............................................... 1,131,339 1,343,475
---------- ----------
Total assets ..................................................... $2,505,633 $2,412,692
========== ==========
LIABILITIES AND TRUST CORPUS
Distributions payable to Unit holders ............................ $ 277,095 $ 261,543
Reserve for future Trust expenses ................................ 1,097,199 807,674
Commitments and contingencies (Note 6)
Trust corpus (4,751,510 Units of beneficial interest authorized
and outstanding) ............................................ 1,131,339 1,343,475
---------- ----------
Total liabilities and Trust corpus ............................... $2,505,633 $2,412,692
========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
-1-
TEL OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------- --------------------------------
1995 1994 1995 1994
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period .............. $ 1,232,357 $ 1,562,788 $ 1,343,475 $ 2,036,295
Distributable income ........................... 277,095 500,394 531,162 2,389,280
Distributions to Unit holders .................. (277,095) (500,394) (531,162) (2,389,280)
Amortization of net overriding
royalty interest .......................... (101,018) (127,621) (212,136) (601,128)
----------- ----------- ----------- -----------
Trust corpus, end of period .................... $ 1,131,339 $ 1,435,167 $ 1,131,339 $ 1,435,167
=========== =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
-2-
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 - TRUST ORGANIZATION
Tenneco Offshore Company, Inc. ("Tenneco Offshore") created
the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan
of Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December
22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership
("Partnership") was formed in which the Trust owns a 99.99% interest and Tenneco
Oil Company ("Tenneco") 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 ("Conveyance").
The dissolution of Exploration I had no impact on future cash distributions to
Unit holders.
On November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired
most of the Gulf of Mexico offshore oil and gas properties of Tenneco, including
all the Royalty Properties. As a result of the acquisition, Chevron replaced
Tenneco as the Working Interest Owner and Managing General Partner of the
Partnership. Chevron also assumed Tenneco's obligations under the Conveyance.
On October 30, 1992, Pennzoil Company ("Pennzoil") acquired
certain oil and gas producing properties from Chevron, including four of the
Royalty Properties. The four Royalty Properties acquired by Pennzoil are East
Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a
result of such acquisition, Pennzoil replaced Chevron as the Working Interest
Owner of such properties on October 30, 1992. Pennzoil also assumed Chevron's
obligations under the Conveyance with respect to such properties.
On December 1, 1994, Texaco Exploration and Production Inc.
("Texaco") acquired one of the Royalty Properties from Chevron. The Royalty
Property acquired by Texaco is West Cameron 643. As a result of such
acquisition, Texaco replaced Chevron as the Working Interest Owner of such
property on December 1, 1994. Texaco also assumed Chevron's obligations under
the Conveyance with respect to such property. All of the Royalty Properties
continue to be subject to the Royalty, and the Trust and the Partnership
continue to operate, in general, 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
thereafter; Pennzoil with respect to East Cameron 354, Eugene Island 348, Eugene
Island 367 and Eugene Island 208 for periods beginning on or after October 30,
1992; and Texaco with respect to West Cameron 643 for periods beginning on or
after December 1, 1994).
-3-
NOTE 2 - BASIS OF ACCOUNTING
The accompanying unaudited financial information has been
prepared by Texas Commerce Bank National Association ("Corporate Trustee") in
accordance with the instructions to Form 10-Q and does not include all of the
information required by generally accepted accounting principles for complete
financial statements, although the Corporate Trustee and the individual trustees
(collectively, "the Trustees") believe that the disclosures are adequate to make
the information presented not misleading. The information furnished reflects all
adjustments which are, in the opinion of the Trustees, necessary for a fair
representation 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, 1994.
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 reserve for
future general and administrative expenses discussed
below in Note 5.
This manner of reporting income and expenses is considered to
be the most meaningful because the quarterly distributions to Unit holders are
based on net cash receipts received from the Working Interest Owners. The
financial statements of the Trust differ from financial statements prepared in
accordance with generally accepted accounting principles, because, under such
principles, Royalty income and Trust general and administrative expenses for a
quarter would be recognized on an accrual basis. In addition, amortization of
the overriding royalty interest, calculated on a unit-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 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" means the amounts received by the Working Interest
Owners from sales of minerals from the Royalty Properties less operating and
capital costs incurred, management fees and expense reimbursements owed the
managing general partner of the Partnership, applicable taxes other than income
taxes, and cash escrows for the future costs to be incurred to plug and abandon
wells and 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
Under the terms of the Trust Agreement, the Trust must
distribute to the Unit holders all cash receipts applicable to the Royalty,
after paying liabilities and providing cash reserves as determined necessary by
the Trustees. 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.
-4-
NOTE 5 - EXPENSE RESERVE
At December 31, 1991, a cash reserve of $120,000 had been
established for future Trust 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
administrative expenses was increased each quarter by an amount equal to the
difference between $150,000 and the amount of the Trust's general and
administrative expenses for such quarter. In March 1994, the Trust determined,
in accordance with the Trust Agreement, to begin further increasing the Trust's
cash reserve each quarter by an amount equal to the difference between $200,000
and the amount of the Trust's general and administrative expenses for such
quarter.
NOTE 6 - COMMITMENTS AND CONTINGENCIES
During 1994, Pennzoil, the Working Interest Owner on the
Eugene Island 348 property, settled a gas imbalance on that property for
approximately $2,696,000. The Trust's share of this settlement amount was
approximately $674,000, of which approximately $122,000 has been recovered from
the Trust by the Working Interest Owner through the third quarter of 1995, and
the remainder will be subject to recovery from the Trust in future periods, in
accordance with the Conveyance. The Working Interest Owner has advised the Trust
that future Royalty income attributable to all of the Royalty Properties owned
by Pennzoil will be used to offset the Trust's share of such settlement amounts.
Based on current production, prices and expenses for the Royalty Properties
owned by Pennzoil, it is estimated that Royalty income attributable to such
properties will be retained by Pennzoil for the remaining life of the Trust. The
Trust does not anticipate that retention of such Royalty income by Pennzoil will
have a material effect on the Trust's Royalty income as a whole.
The Working Interest Owners have advised the Trust that,
although they believe that they are in general compliance with applicable
health, safety and environmental laws and regulations that have taken effect at
the federal, state and local levels, costs may be incurred to comply with
current and proposed environmental legislation which could result in increased
operating expenses on the Royalty Properties.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL REVIEW
THREE MONTHS ENDED SEPTEMBER 30, 1995 AND 1994
Distributions to Unit holders for the three months ended
September 30, 1995 amounted to $277,095 or $.058317 per Unit as compared to
$500,394 or $.105312 per Unit for the same period in 1994. The decrease in
distributable income for the third quarter of 1995 was primarily due to a
larger release of funds from the Special Cost Escrow Account (discussed below)
in the third quarter of 1994 compared to the net release of funds from the
Special Cost Escrow Account in the third quarter of 1995. In addition, gas
revenues decreased approximately 43% in the third quarter of 1995 as compared to
the third quarter of 1994 primarily due to a 34% decrease in gas volumes. This
decrease in gas volumes was primarily attributable to the continued natural
production decline as the Royalty Properties approach the end of their
productive lives. There also was a 17% decrease in the average price
received for natural gas from $1.99 per Mcf in the third quarter of 1994 to
$1.66 per Mcf in the third quarter of 1995. Crude oil revenues increased
approximately 13% in the third quarter of 1995 in comparison to the same period
in 1994 primarily due to a 12% increase in crude oil and condensate volumes as a
result of a system adjustment in the Eugene Island 339 field in the first
quarter of 1995. In addition, there was an increase in the average price
received from $16.21 per barrel in the third quarter of 1994 to $16.38 per
barrel in the third quarter of 1995. The increase in volumes and average prices
was offset in part by the continued natural production decline as the properties
approach the end of their productive lives. The Trust's share of operating
expenses, excluding the gas imbalance settlement discussed below, decreased by
approximately $193,000 in the third quarter of 1995 as compared to the same
period in 1994 due primarily to expenses incurred in the third quarter of 1994
in connection with workovers on the A-1, A-2, A-4 and A-7 wells on the West
-5-
Cameron 643 property. The Trust's share of capital expenditures increased by
approximately $83,000 in the third quarter of 1995 as compared to the same
period in 1994 due primarily to the B-3 well workover performed on the West
Cameron 643 property in the third quarter of 1995.
In the third quarter of 1994, Pennzoil, the Working Interest
Owner on the Eugene Island 348 property, expensed approximately $674,000, in
accordance with the Conveyance, as partial payment of a gas imbalance settlement
on that property. The Trust's share of this partial payment was approximately
$168,500, which was reflected as an increase in operating expenses.
In the third quarter of 1995, there was a net release of funds
from the Special Cost Escrow Account. The Trust's share of the funds released
was approximately $1,875 which increased distributable income for the period.
During the third quarter of 1994, there was a release of funds from the Special
Cost Escrow Account, the Trust's share of which was approximately $290,949. The
Special Cost Escrow is set aside for estimated abandonment costs and future
capital expenditures as provided for in the Conveyance. (For additional
information relating to the Special Cost Escrow see page 10 of this Form 10-Q.)
NINE MONTHS ENDED SEPTEMBER 30, 1995 AND 1994
Distributions to Unit holders for the nine months ended
September 30, 1995 amounted to $531,162 or $.111787 per Unit as compared to
$2,389,280 or $.502845 per Unit for the same period in 1994. The decrease in
distributable income for the first nine months of 1995 was primarily due to a
net deposit of funds into the Special Cost Escrow Account (discussed below) in
the first nine months of 1995 compared to the net release of funds from the
Special Cost Escrow Account for the same period in 1994. Gas revenues decreased
approximately 36% in the first nine months of 1995 as compared to the first nine
months of 1994 primarily due to a 24% decrease in the average price received for
natural gas from $2.20 per Mcf in the first nine months of 1994 to $1.68 per Mcf
in the first nine months of 1995. In addition, there was a 19% decrease in gas
volumes. This decrease in gas volumes was primarily attributable to the C-10
well being watered out and the C-4 well being sanded in on the Ship Shoal
182/183 property throughout the second quarter of 1995 and a continued natural
production decline as the Royalty Properties approach the end of their
productive lives. Crude oil revenues increased approximately 4% in the first
nine months of 1995 in comparison to the same period in 1994 primarily due to an
increase in the average price received from $13.94 per barrel in the first nine
months of 1994 to $16.22 per barrel in the first nine months of 1995. The
increase in the average price received was partially offset by an 11% decrease
in crude oil and condensate volumes for the first nine months of 1995 in
comparison to the same period in 1994. The decrease in crude oil and condensate
volumes was primarily attributable to a continued natural production decline as
the Royalty Properties approach the end of their productive lives. The Trust's
share of operating expenses, excluding the gas imbalance settlement discussed
above, decreased by approximately $390,800 in the first nine months of 1995 as
compared to the same period in 1994 due primarily to expenses incurred in the
first nine months of 1994 in connection with a workover performed on the B-13
well on the Eugene Island 339 property and workovers performed on four wells on
the West Cameron 643 property. The Trust's share of capital expenditures
increased by approximately $158,700 in the first nine months of 1995 in
comparison to the first nine months of 1994 primarily due to expenses incurred
in the first quarter of 1995 in connection with the installation of a
Supervisory Control and Data Acquisition system on the West Cameron 643 property
and the B-3 well workover performed on the West Cameron 643 property in the
third quarter of 1995.
In the first nine months of 1995 there was a net deposit of
funds into the Special Cost Escrow Account. The Trust's share of the funds
deposited was approximately $95,339, which decreased distributable income for
the period. During the first nine months of 1994, there was a net release of
funds from the Special Cost Escrow Account. The Trust's share of the funds
released was approximately $1,669,084. (For additional information relating to
the Special Cost Escrow see page 10 of this Form 10-Q.)
-6-
RESERVE FOR FUTURE TRUST EXPENSES
In accordance with the provisions of the Trust Agreement, 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, generally 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 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 expense for such quarter. In March 1994, the
Trust determined, in accordance with the Trust Agreement, to begin further
increasing the Trust's cash reserve each quarter by an amount equal to the
difference between $200,000 and the amount of the Trust's general and
administrative expenses for such quarter. General and administrative expenses of
the Trust were approximately $71,800 in the third quarter of 1995. Accordingly,
the Trust's cash reserve was increased by approximately $128,200 in such
quarter, bringing the total amount of the Trust's cash reserve at September 30,
1995 to approximately $1,097,200.
OTHER
The amount of cash distributed by the Trust is dependent on,
among other things, the sales prices and quantities of oil and gas produced from
the Royalty Properties. It should be noted that substantial uncertainties exist
with regard to future oil and gas prices, which are subject to material
fluctuations due to changes in production levels and pricing and other actions
taken by major petroleum producing nations, as well as the regional supply and
demand for oil and gas, weather, industrial growth, conservation measures,
competition and other variables.
OPERATIONAL REVIEW
THREE MONTHS ENDED SEPTEMBER 30, 1995 AND 1994
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS
RECORDED BY THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 gas revenues decreased 58% from $282,357 in
the third quarter of 1994 to $119,527 in the third quarter of 1995, primarily
due to a decrease in gas volumes. Gas volumes decreased from 145,009 Mcf in the
third quarter of 1994 to 60,447 Mcf in the third quarter of 1995 due primarily
to the C-4 well being sanded in throughout the third quarter of 1995. The
Working Interest Owner has advised the Trust that it cannot predict at this time
when production will resume on the C-4 well. In addition, there was a decrease
in the average natural gas sales price for Ship Shoal 182/183 from $1.99 per Mcf
in the third quarter of 1994 to $1.94 per Mcf in the same period of 1995. The
majority of the gas from this property is being purchased by Tennessee Gas
Pipeline Company ("Tennessee Gas") pursuant to an agreement providing for gas to
be purchased at a calculated monthly price based on the spot market rate. An 11%
decrease in crude oil production from 70,650 barrels in the third quarter of
1994 to 62,930 barrels in the third quarter of 1995 and a 1% increase in average
crude oil prices from $16.20 per barrel in the third quarter of 1994 to $16.40
per barrel for the same period in 1995 resulted in a 10% decrease in crude oil
revenues from $1,144,683 in the third quarter of 1994 to $1,032,141 in the third
quarter of 1995. The decrease in crude oil production was primarily due to a
continued natural production decline. The Working Interest Owner has advised the
Trust that approximately 60,500 Mcf has been overtaken by the Working Interest
Owner from this property. The Trust's share of this overtake position is
approximately 15,125 Mcf. Accordingly, gas revenues from this property may be
reduced in future periods while underproduced parties recover their share of the
gas imbalance. Operating expenses increased from $344,182 in the third quarter
of 1994 to $409,364 in the third quarter of 1995 due primarily to workovers
performed on the C-9 and C-12 wells in the third quarter of 1995.
Eugene Island 339 gas revenues decreased 54% from $325,182 in
the third quarter of 1994 to $148,123 in the third quarter of 1995 due primarily
to a decrease in volumes from 168,733 Mcf in the third quarter of 1994 to 87,650
Mcf for the same period in 1995. The decrease in gas volumes was primarily due
to reduced takes in an effort to reduce an overbalance position and the
continued natural decline in the productive capacity of the property.
-7-
In addition, there was a decrease in the average price received for natural gas
from $1.98 in the third quarter of 1994 to $1.60 in the third quarter of 1995.
The Working Interest Owner has advised the Trust that at September 30, 1995
there was an overtake imbalance position of approximately 382,300 Mcf on this
property. The Trust's share of this overtake position was approximately 95,575
Mcf. Accordingly, gas revenues from this property may be reduced in future
periods while underproduced parties recoup their share of the gas imbalance. The
gas from this property is currently committed to Tennessee Gas pursuant to an
agreement providing for gas to be purchased at a calculated monthly price based
on the spot market rate. Crude oil revenues increased from $945,672 in the third
quarter of 1994 to $1,340,167 in the third quarter of 1995. This increase was
primarily due to an increase in volumes from 58,440 barrels in the third quarter
of 1994 to 81,878 barrels in the third quarter of 1995 as a result of an
adjustment of approximately 20,000 barrels (5,000 barrels net to the Trust) due
to a system adjustment in the first quarter of 1995. In addition, there was an
increase in the average price received for crude oil and condensate from $16.18
per barrel in the third quarter of 1994 to $16.37 per barrel in the third
quarter of 1995. Operating expenses decreased from $637,172 in the third quarter
of 1994 to $340,575 in the third quarter of 1995 due primarily to expenses
incurred in the third quarter of 1994 in connection with the workover on the
B-13 well. The Working Interest Owner has also advised the Trust that it has
purchased a three dimensional seismic survey of this property. The survey
continues to be evaluated by the Working Interest Owner.
West Cameron 643 gas revenues decreased 54% from $634,596 in
the third quarter of 1994 to $290,666 in the third quarter of 1995 primarily due
to a decease in gas volumes. Gas volumes decreased from 319,259 Mcf in the third
quarter of 1994 to 185,172 Mcf in the same period of 1995 primarily due to
decreased takes and a continued natural production decline. The decrease in
takes by the Working Interest Owner was primarily due to a decrease in the
average price received for natural gas from $1.99 per Mcf in the third quarter
of 1994 to $1.57 per Mcf in the third quarter of 1995. The Working Interest
Owner has advised the Trust that at September 30, 1995 there was an undertake
imbalance position of approximately 2,000 Mcf (500 Mcf net to the Trust) on this
property. Operating expenses decreased from $616,175 in the third quarter of
1994 to $79,275 in the third quarter of 1995 due primarily to expenses incurred
in the third quarter of 1994 in connection with workovers on the A-1, A-2, A-4
and A-7 wells. In addition, the Working Interest Owner has advised the Trust
that it intends to perform six workovers on the A-2, A-6, A-9, A-10, A-16 and
A-17 wells in the fourth quarter of 1995 at an estimated cost of $1,395,300
($348,825 net to the Trust).
The Working Interest Owner on Eugene Island 348 resumed taking
gas in the second quarter of 1995. The Working Interest Owner had eliminated gas
takes beginning the first quarter of 1992 and continuing through the first
quarter of 1995 in connection with a previous overtake imbalance position that
was settled by the Working Interest Owner in 1994 (see Note 6 in the Notes to
Financial Statements elsewhere herein). The Working Interest Owner advised the
Trust that the overtake imbalance position was approximately 48,400 Mcf on
this property at September 30, 1995. The Trust's share of this new overtake
position is approximately 12,100 Mcf. Accordingly, gas revenues attributable to
the Royalty on this property may be reduced in future periods while
underproduced parties continue to recoup their share of this gas imbalance. In
addition, the Working Interest Owner has advised the Trust that it no longer
intends to drill a development well on this property in the fourth quarter of
1995.
NINE MONTHS ENDED SEPTEMBER 30, 1995 AND 1994
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS
RECORDED BY THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 gas revenues decreased 71% from $1,211,185
in the first nine months of 1994 to $353,661 in the first nine months of 1995,
primarily due to a decrease in gas volumes. Gas volumes decreased from 548,188
Mcf in the first nine months of 1994 to 194,030 Mcf in the first nine months of
1995 due primarily to the C-10 well being watered out and the C-4 well being
sanded in during portions of the second and third quarters of 1995. The Working
Interest Owner has advised the Trust that the C-10 well resumed production in
May 1995. In addition, there was a decrease in the average natural gas sales
price for Ship Shoal 182/183 from $2.25 per Mcf in the first nine months of 1994
to $1.81 per Mcf in the same period of 1995. An 18% decrease in crude oil
production from 237,980 barrels in the first nine months of 1994 to 194,620
barrels in the first nine months of 1995 and a 17% increase in the average crude
oil prices from $13.89 per barrel in the first nine months of 1994 to $16.30 per
barrel for the same period in 1995 resulted in a 4% decrease in crude oil
revenues from $3,305,535 in the first nine months of 1994 to $3,172,152
-8-
in the first nine months of 1995. The decrease in crude oil production was
primarily due to a continued natural production decline. Operating expenses
increased from $953,112 in the first nine months of 1994 to $1,023,607 in the
first nine months of 1995 due primarily to workovers performed on the C-9 and
C-12 wells in the second and third quarters of 1995.
Eugene Island 339 gas revenues decreased 10% from $951,875 in
the first nine months of 1994 to $858,710 in the first nine months of 1995 due
primarily to a decrease in the average price received for natural gas from $2.27
in the first nine months of 1994 to $1.75 in the first nine months of 1995. The
decrease in the average price received for gas was offset partially by an
increase in volumes from 439,820 Mcf in the first nine months of 1994 to 468,932
Mcf for the same period in 1995. The increase in gas volumes was primarily due
to a revised volume allocation between purchasers of approximately 45,300 Mcf
(11,325 Mcf net to the Trust) on this property in the first quarter of 1995 and
a meter statement downward adjustment of approximately 42,000 Mcf (10,500 Mcf
net to the Trust) on this property in the first quarter of 1994. Crude oil
revenues increased from $2,412,775 in the first nine months of 1994 to
$2,788,859 in the first nine months of 1995. This increase was primarily due to
an increase in the average price received for crude oil and condensate from
$13.94 per barrel in the first nine months of 1994 to $16.15 per barrel in the
first nine months of 1995. The increase in the average price received was
partially offset by a slight decrease in crude oil and condensate volumes for
the first nine months of 1995 in comparison to the same period in 1994.
Operating expenses decreased from $1,943,884 in the first nine months of 1994 to
$1,187,171 in the first nine months of 1995 due primarily to expenses incurred
in the second and third quarters of 1994 in connection with the well workover on
the B-13 well.
West Cameron 643 gas revenues decreased 51% from $1,415,043 in
the first nine months of 1994 to $705,252 in the first nine months of 1995
primarily as a result of a decrease in volumes from 668,493 Mcf in the first
nine months of 1994 to 437,940 Mcf in the same period in 1995. The decrease in
gas volumes was primarily due to decreased takes and a continued natural
production decline. The decrease in takes by the Working Interest Owner was
primarily due to a decrease in the average price received for natural gas from
$2.12 per Mcf in the first nine months of 1994 to $1.61 per Mcf in the first
nine months of 1995. Operating expenses decreased from $971,560 in the first
nine months of 1994 to $245,362 in the first nine months of 1995 primarily due
to expenses incurred in the second and third quarters of 1994 in connection with
workovers on the A-1, A-2, A-4 and A-7 wells. Capital expenditures increased
from $2,809 in the first nine months of 1994 to $603,188 in the first nine
months of 1995 due primarily to a Supervisory Control and Data Acquisition
system installation on the property in the first quarter of 1995 and a workover
on the B-3 well in the second quarter of 1995.
FUTURE NET REVENUES AND TERMINATION OF THE TRUST
Based on information provided to the Trust by DeGolyer and
MacNaughton, independent petroleum engineers, it was estimated as of October 31,
1994 that approximately 66% of the future net revenues from the Royalty
Properties were expected to be received by the Trust during the next 3 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 estimate discussed above is 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 any 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 1994 Annual Report on Form 10-K. The Form 10-K is
available upon request from the Corporate Trustee.
-9-
SPECIAL COST ESCROW
The Conveyance provides for reserving funds for estimated
future "Special Costs" of plugging and abandoning wells, dismantling platforms
and other costs of abandoning the leases, as well as for the estimated amount of
future drilling projects and other capital expenditures on the leases. As
provided by 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."
Interest generated from the Special Cost Escrow Account serves to reduce the
Partnership'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 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 paid. 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 1994, there was a net release of funds from
the Special Cost Escrow Account in the amount of $1,669,084 primarily as a
result of a decrease in future estimated Special Costs of the Royalty
Properties. This decrease was due in part to a decrease in estimated abandonment
costs as a result of technological improvements in abandonment procedures
utilized by the Working Interest Owners and fewer capital projects planned in
the future. In the first nine months of 1995, a net deposit of $95,339 was made
into the Special Cost Escrow Account. The deposit was primarily a result of an
increase in the current estimate of projected capital expenditures on the
Royalty Properties. As of September 30, 1995, approximately $2,471,600 remained
in the Special Cost Escrow Account. 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.
-10-
<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, 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)
----------------------------
1995 1994
----------- -----------
Crude oil and condensate (bbls) ........... 147,290 131,710
Natural gas and gas products (Mcf) ........ 432,740 657,499
Crude oil and condensate average
price, per bbl ........................ $ 16.38 $ 16.21
Natural gas average price, per Mcf
(excluding gas products) .............. $ 1.66 $ 1.99
Crude oil and condensate revenues ......... $ 2,412,616 $ 2,135,405
Natural gas and gas products revenues ..... 730,243 1,291,621
Production expenses ....................... (905,265) (1,767,988)(2)
Capital expenditures ...................... (370,150) (37,590)
Refund of escrowed special costs .......... 7,500 1,163,796
----------- -----------
NET PROCEEDS .............................. 1,874,944 2,785,244
Royalty interest .......................... x 25% x 25%
----------- -----------
Partnership share ......................... 468,736 696,311
Trust interest ............................ x 99.99% x 99.99%
----------- -----------
Trust share ............................... $ 468,689 $ 696,241
=========== ===========
- ------------
(1) The amounts for the three months ended September 30, 1995 and 1994
represent actual production for the periods May 1995 through July 1995 and
May 1994 through July 1994, respectively.
(2) Includes a reduction of approximately $12,000 ($3,000 net to the Trust) in
connection with the gas imbalance settlement on the Eugene Island 348
property. For more information, see Note 6 to the Notes to Financial
Statements.
-11-
<PAGE>
Royalty Properties
Nine Months Ended
September 30, (1)
----------------------------
1995 1994
----------- ------------
Crude oil and condensate (bbls) ............ 373,902 418,947
Natural gas and gas products (Mcf) ......... 1,431,927 1,765,432
Crude oil and condensate average price,
per bbl ................................ $ 16.22 $ 13.94
Natural gas average price, per Mcf
(excluding gas products) ............... $ 1.68 $ 2.20
Crude oil and condensate revenues .......... $ 6,066,428 $ 5,838,796
Natural gas and gas products revenues ...... 2,457,231 3,821,284
Production expenses ........................ (3,004,888) (4,352,795)(2)
Capital expenditures ....................... (700,763) (65,957)
(Provision for) Refund of escrowed
special costs .......................... (381,356) 6,676,336
----------- ------------
NET PROCEEDS ............................... 4,436,652 11,917,664
Royalty interest ........................... x 25% x 25%
----------- ------------
Partnership share .......................... 1,109,163 2,979,416
Trust interest ............................. x 99.99% x 99.99%
----------- ------------
Trust share ................................ $ 1,109,052 $ 2,979,118
=========== ============
- ------------
(1) The amounts for the nine months ended September 30, 1995 and 1994 represent
actual production for the periods November 1994 through July 1995 and
November 1993 through July 1994, respectively.
(2) Includes a reduction of approximately $12,000 ($3,000 net to the Trust) in
connection with the gas imbalance settlement on the Eugene Island 348
property. For more information, see Note 6 to the Notes to Financial
Statements.
-12-
<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>
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)
-13-
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 1995.
-14-
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TEL OFFSHORE TRUST
By TEXAS COMMERCE BANK
NATIONAL ASSOCIATION
Corporate Trustee
By /s/ MIKE ULRICH
Mike Ulrich
Senior Vice President
and Trust Officer
Date: November 13, 1995
The Registrant, TEL Offshore Trust, has no principal executive officer,
principal financial officer, board of directors or persons performing similar
functions. Accordingly, no additional signatures are available and none have
been provided.
-15-
<PAGE>
<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-30-1995 AND THE
STATEMENT OF DISTRIBUTABLE INCOME FOR THE NINE MONTHS ENDED SEP-30-1995 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> SEP-30-1995
<CASH> 1,374,294
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,374,294
<PP&E> 28,267,655
<DEPRECIATION> 27,136,316
<TOTAL-ASSETS> 2,505,633
<CURRENT-LIABILITIES> 277,095
<BONDS> 0
<COMMON> 0
0
0
<OTHER-SE> 1,131,339
<TOTAL-LIABILITY-AND-EQUITY> 2,505,633
<SALES> 0
<TOTAL-REVENUES> 1,131,162
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 600,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 531,162
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 531,162
<EPS-PRIMARY> .112
<EPS-DILUTED> .112
</TABLE>
