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, 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 AUGUST 1, 1995 - 4,751,510 UNITS OF BENEFICIAL INTEREST IN TEL
OFFSHORE TRUST.
<PAGE>
PART I - FINANCIAL INFORMATION
ITEM 1 - FINANCIAL STATEMENTS
TEL OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- --------------------------
1995 1994 1995 1994
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Royalty income ............................. $ 377,894 $ 677,359 $ 640,363 $ 2,282,877
Interest income ............................ 7,554 3,371 13,704 6,009
----------- ----------- ----------- -----------
385,448 680,730 654,067 2,288,886
Increase in expense reserve ................ (80,792) (71,064) (161,356) (137,111)
General and administrative expense ......... (119,208) (128,936) (238,644) (262,889)
----------- ----------- ----------- -----------
Distributable income ....................... $ 185,448 $ 480,730 $ 254,067 $ 1,888,886
=========== =========== =========== ===========
Distributions per Unit
(4,751,510 Units) ..................... $ .039029 $ .101174 $ .053470 $ .397533
=========== =========== =========== ===========
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1995 1994
---------- ------------
(UNAUDITED)
<S> <C> <C>
ASSETS
Cash and cash equivalents ............................................................ $1,154,478 $1,069,217
Net overriding royalty interest in producing oil and gas
properties net of accumulated amortization of
$27,035,298 and $26,924,180, respectively .......................................... 1,232,357 1,343,475
---------- ----------
Total assets ......................................................................... $2,386,835 $2,412,692
========== ==========
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders ................................................. $ 185,448 $ 261,543
Reserve for future Trust expenses .................................................... 969,030 807,674
Commitments and contingencies (Note 6)
Trust corpus (4,751,510 Units of beneficial interest
authorized and outstanding) ........................................................ 1,232,357 1,343,475
---------- ----------
Total liabilities and Trust corpus ................................................... $2,386,835 $2,412,692
========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
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<PAGE>
TEL OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------------- --------------------------------
1995 1994 1995 1994
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Trust corpus,
beginning of period ........................ $ 1,303,796 $ 1,695,161 $ 1,343,475 $ 2,036,295
Distributable income ........................... 185,448 480,730 254,067 1,888,886
Distributions to Unit holders .................. (185,448) (480,730) (254,067) (1,888,886)
Amortization of net overriding
royalty interest ........................... (71,439) (132,373) (111,118) (473,507)
----------- ----------- ----------- -----------
Trust corpus, end of period .................... $ 1,232,357 $ 1,562,788 $ 1,232,357 $ 1,562,788
=========== =========== =========== ===========
</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") 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 ("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
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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).
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
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, 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
-4-
Interest Owners from sales of minerals from the Royalty Properties less
operating and capital costs incurred, management fees and expense reimbursements
owing 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.
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 $88,000 has been recovered from the Trust by
the Working Interest Owner through the second 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.
-5-
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 JUNE 30, 1995 AND 1994
Distributions to Unit holders for the three months ended June 30, 1995
amounted to $185,448 or $.039029 per Unit as compared to $480,730 or $.101174
per Unit for the same period in 1994. The decrease in distributable income for
the second quarter of 1995 was primarily due to a net deposit of funds into the
Special Cost Escrow Account (discussed below) in the second quarter of 1995
compared to a net release of funds from the Special Cost Escrow Account in the
second quarter of 1994. Gas revenues decreased approximately 46% in the second
quarter of 1995 as compared to the second quarter of 1994 primarily due to a 25%
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. In addition, there was a 32% decrease in the average price
received for natural gas from $2.28 per Mcf in the second quarter of 1994 to
$1.55 per Mcf in the second quarter of 1995. Crude oil revenues increased
approximately 13% in the second quarter of 1995 in comparison to the same period
in 1994 primarily due to a 31% increase in the average price received from
$12.75 per barrel in the second quarter of 1994 to $16.66 per barrel in the
second quarter of 1995. This increase in the average price was partially offset
by a 14% decrease in crude oil and condensate volumes from the 1994 second
quarter to the 1995 second quarter. This decrease in crude oil and condensate
volumes was primarily attributable to a continued natural production decline as
the properties approach the end of their productive lives. The Trust's share of
operating expenses decreased by approximately $103,000 in the second quarter of
1995 as compared to the same period in 1994 due primarily to expenses incurred
in the second quarter of 1994 in connection with workovers performed on four
wells on the West Cameron 643 property.
In the second quarter of 1995, there was a deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $37,931, which decreased distributable income for the period.
During the second quarter of 1994, there was a net release of funds from the
Special Cost Escrow Account, the Trust's share of which was approximately
$196,135. 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 11 of this
Form 10-Q.)
-6-
SIX MONTHS ENDED JUNE 30, 1995 AND 1994
Distributions to Unit holders for the six months ended June 30, 1995
amounted to $254,067 or $.053470 per Unit as compared with $1,888,886 or
$.397533 per Unit for the same period in 1994. The decrease in distributable
income for the first six months of 1995 was primarily due to a net deposit of
funds into the Special Cost Escrow Account (discussed below) in the first six
months of 1995 compared to a net release of funds from the Special Cost Escrow
Account for the same period in 1994. Gas revenues decreased approximately 32% in
the first six months of 1995 as compared to the first six months of 1994
primarily due to a 28% decrease in the average price received for natural gas
from $2.32 per Mcf in the first six months of 1994 to $1.68 per Mcf in the first
six months of 1995. In addition, there was a 10% 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. A 21%
decrease in crude oil and condensate volumes from the first six months of 1994
to the first six months of 1995 offset by a 25% increase in the average price
received from $12.89 per barrel in the first six months of 1994 to $16.12 per
barrel in the first six months of 1995 resulted in a 1% decrease in crude oil
revenues for the first six months of 1995 compared to the first six months of
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 decreased by approximately $198,000 in the first six months of 1995 as
compared to the same period in 1994 due primarily to expenses incurred in the
first six 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 $76,000 in the first six months of 1995 in comparison
to the first six 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.
In the first six 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 $97,224, which decreased distributable income for the period.
During the first six 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 $1,378,135. (For additional information relating to the Special
Cost Escrow see page 11 of this Form 10-Q.)
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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 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. General and administrative expenses of
the Trust were approximately $119,200 in the second quarter of 1995.
Accordingly, the Trust's cash reserve was increased by approximately $80,800 in
such quarter, bringing the total amount of the Trust's cash reserve at June 30,
1995 to approximately $969,000.
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, 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 from $427,381 in the second
quarter of 1994 to $32,245 in the second quarter of 1995, primarily due to a
large decrease in gas volumes. Gas volumes decreased from 185,397 Mcf in the
second quarter of 1994 to 18,777 Mcf in the second quarter of 1995 due primarily
to the C-10 well being watered out and the C-4 well being sanded in throughout
the second quarter of 1995. The Working Interest Owner has advised the Trust
that the C-10 well resumed production in May 1995 and 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
$2.33 per Mcf in the second quarter of 1994 to $1.72 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. A 22% decrease in crude oil production from 78,616 barrels in
the second quarter of 1994 to 60,950 barrels in the second quarter of 1995 and a
31% increase in average crude oil prices from $12.78 per barrel in the second
quarter of 1994 to $16.73 per barrel for the same period in 1995 resulted in a
2% increase in
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crude oil revenues from $1,004,506 in the second quarter of 1994 to $1,019,818
in the second 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 60,000 Mcf has been overtaken by
the Working Interest Owner from this property. The Trust's share of this
overtake position is approximately 15,000 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
$279,325 in the second quarter of 1994 to $325,601 in the second quarter of 1995
due primarily to workovers performed on the C-9 and C-12 wells in the second
quarter of 1995.
Eugene Island 339 gas revenues decreased 32% from $439,978 in the
second quarter of 1994 to $299,836 in the second quarter of 1995 due primarily
to a decrease in the average price received for natural gas from $2.43 per Mcf
in the second quarter of 1994 to $1.62 per Mcf in the second quarter of 1995. In
addition, there was a 6% decrease in gas volumes from 185,426 Mcf in the second
quarter of 1994 to 174,532 Mcf in the second quarter of 1995. The decrease in
gas volumes was primarily due to a continued natural decline in the productive
capacity of the property. The Working Interest Owner has advised the Trust that
there is an overtake imbalance position of approximately 508,000 Mcf on this
property. The Trust's share of this overtake position is approximately 127,000
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 $753,999 in the
second quarter of 1994 to $974,938 in the second quarter of 1995 due primarily
to an increase in the average price received for crude oil and condensate from
$12.66 per barrel in the second quarter of 1994 to $16.59 per barrel in the
second quarter of 1995. The price increase was slightly offset by a 1% decrease
in volumes from 59,536 barrels in the second quarter of 1994 to 58,769 barrels
for the same period in 1995. Operating expenses decreased from $673,131 in the
second quarter of 1994 to $413,234 in the second quarter of 1995 due primarily
to expenses incurred in the second quarter of 1994 in connection with the well
workover on the B-13 well completed in the second quarter of 1994. The Working
Interest Owner has advised the Trust that it intends to plug back the B-18 well
on this property in late 1995 or early 1996 at an estimated cost of $21,235 net
to the Trust. The Working Interest Owner has also advised the Trust that it has
purchased a three dimensional seismic survey of this property. The survey is
currently being evaluated by the Working Interest Owner.
West Cameron 643 gas revenues decreased 66% from $476,013 in the
second quarter of 1994 to $161,104 in the second quarter of 1995, primarily due
to a decrease in gas volumes. Gas volumes decreased from 227,024 Mcf in the
second quarter of 1994 to 110,177 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 $2.10 per Mcf in the second quarter
of 1994 to $1.46 per Mcf in the second quarter of 1995. The Working Interest
Owner has advised the Trust that there is an undertake imbalance position of
approximately 3,200 Mcf (800 Mcf net to the Trust) on this property. Operating
expenses decreased from $196,366 in the second quarter of 1994 to $43,042 in the
second quarter of 1995 due primarily to expenses incurred in the second 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
drill a development well on this property in the
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third quarter of 1995.
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, has advised the Trust
that there is a new overtake imbalance position of approximately 58,000 Mcf on
this property. The Trust's share of this new overtake position is approximately
14,500 Mcf. Accordingly, gas revenues attributable to the Royalty on this
property may be reduced in future periods while underproduced parties recoup
their share of this gas imbalance. In addition, the Working Interest Owner has
advised the Trust that it intends to drill a development well on this property
in the fourth quarter of 1995. The cost of such drilling is expected to be
approximately $1,184,000 ($296,000 net to the Trust).
SIX MONTHS ENDED JUNE 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 from $928,828 in the first
six months of 1994 to $234,134 in the first six months of 1995, primarily due to
a large decrease in gas volumes. Gas volumes decreased from 403,179 Mcf in the
first six months of 1994 to 133,583 Mcf in the first six months of 1995 due
primarily to the C-10 well being watered out and the C-4 well being sanded in
throughout the second quarter of 1995. In addition, there was a decrease in the
average natural gas sales price for Ship Shoal 182/183 from $2.33 per Mcf in the
first six months of 1994 to $1.74 per Mcf in the same period of 1995. A 21%
decrease in crude oil production from 167,330 barrels in the first six months of
1994 to 131,690 barrels in the first six months of 1995 and a 26% increase in
average crude oil prices from $12.91 per barrel in the first six months of 1994
to $16.25 per barrel for the same period in 1995 resulted in a 1% decrease in
crude oil revenues from $2,160,852 in the first six months of 1994 to $2,140,011
in the first six months of 1995. The decrease in crude oil production was
primarily due to a continued natural production decline.
Eugene Island 339 gas revenues increased from $626,693 in the first
six months of 1994 to $710,587 in the first six months of 1995 due to an
increase in gas volumes from 271,087 Mcf in the first six months of 1994 to
381,282 Mcf for the same period in 1995. The increase in gas volumes was due
primarily 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. The
increase in volumes was offset partially by a decrease in the average price
received for natural gas from $2.43 per Mcf in the first six months of 1994 to
$1.79 per Mcf in the first six months of 1995. Crude oil revenues decreased from
$1,467,103 in the first six months of 1994 to $1,448,692 in the first six months
of 1995 due in part to a 21% decrease in volumes from 114,620 barrels in the
first six months of 1994 to 90,826 barrels for the same period in 1995. This
decrease in volumes was primarily attributable to the wells being temporarily
shut in on this property in the first quarter of 1995 in connection with rig
mobilizing
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and demobilizing associated with drilling activities of the operator on
non-trust properties. This decrease in volumes was partially offset by an
increase in the average price received for crude oil and condensate from $12.80
per barrel in the first six months of 1994 to $15.95 per barrel in the first six
months of 1995. Operating expenses decreased from $1,306,712 in the first six
months of 1994 to $846,596 in the first six months of 1995 due primarily to
expenses incurred in the second quarter of 1994 in connection with the well
workover on the B-13 well.
West Cameron 643 gas revenues decreased 47% from $780,447 in the first
six months of 1994 to $414,586 in the first six months of 1995, primarily due to
a decrease in gas volumes. Gas volumes decreased from 349,234 Mcf in the first
six months of 1994 to 252,768 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 $2.23 per Mcf in the first six
months of 1994 to $1.64 per Mcf in the first six months of 1995. Operating
expenses decreased from $355,385 in the first six months of 1994 to $166,087 for
the same period in 1995 due primarily to expenses incurred in the second quarter
of 1994 in connection with workovers on the A-1, A-2, A-4 and A-7 wells. Capital
expenditures increased from $9,323 in the first six months of 1994 to $244,497
in the first six months of 1995 due primarily to a Supervisory Control and Data
Acquisition system installation on the property in the first 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 that as of
October 31, 1994 approximately 66% of the future net revenues from the Royalty
Properties are 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.
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
-11-
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 six months of 1994, there was a net
release of funds from the Special Cost Escrow Account in the amount of
$1,378,135. The release was primarily a result of a decrease in future estimated
Special Costs of the Royalty Properties 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 six months of 1995, a net deposit of
approximately $97,200 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 June 30, 1995,
approximately $2,461,700 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.
-12-
<PAGE>
OVERVIEW OF PRODUCTION, PRICES AND NET PROCEEDS
The following schedule provides a summary of the volumes and weighted
average prices for crude oil and condensate and natural gas recorded by the
Working Interest Owners, 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)
-------------------------
1995 1994
----------- -----------
Crude oil and condensate (bbls) .................... 121,694 140,772
Natural gas and gas products (Mcf) ................. 490,437 653,295
Crude oil and condensate average price, per bbl .... $ 16.66 $ 12.75
Natural gas average price, per Mcf
(excluding gas products) ......................... $ 1.55 $ 2.28
Crude oil and condensate revenues .................. $ 2,027,148 $ 1,794,711
Natural gas and gas products revenues .............. 790,811 1,473,044
Production expenses ................................ (1,130,162) (1,336,460)
Capital expenditures ............................... (24,345) (6,126)
(Provision for) Refund of escrowed special costs ... (151,724) 784,540
----------- -----------
NET PROCEEDS ....................................... 1,511,728 2,709,709
Royalty interest ................................... x 25% x 25%
----------- -----------
Partnership share .................................. 377,932 677,427
Trust interest ..................................... x 99.99% x 99.99%
----------- -----------
Trust share ........................................ $ 377,894 $ 677,359
=========== ===========
------------
(1) The amounts for the three months ended June 30, 1995 and 1994 represent
actual production for the periods February 1995 through April 1995 and
February 1994 through April 1994, respectively.
-13-
<PAGE>
ROYALTY PROPERTIES
SIX MONTHS ENDED
JUNE 30,(1)
-------------------------
1995 1994
----------- -----------
Crude oil and condensate (bbls) .................... 226,612 287,237
Natural gas and gas products (Mcf) ................. 999,187 1,107,934
Crude oil and condensate average price, per bbl .... $ 16.12 $ 12.89
Natural gas average price, per Mcf
(excluding gas products) ......................... $ 1.68 $ 2.32
Crude oil and condensate revenues .................. $ 3,653,812 $ 3,703,391
Natural gas and gas products revenues .............. 1,726,988 2,529,663
Production expenses ................................ (2,099,623) (2,584,807)
Capital expenditures ............................... (330,613) (28,367)
(Provision for) Refund of escrowed special costs ... (388,856) 5,512,540
----------- -----------
NET PROCEEDS ....................................... 2,561,708 9,132,420
Royalty interest ................................... x 25% x 25%
----------- -----------
Partnership share .................................. 640,427 2,283,105
Trust interest ..................................... x 99.99% x 99.99%
----------- -----------
Trust share ........................................ $ 640,363 $ 2,282,877
=========== ===========
(1) The amounts for the six months ended June 30, 1995 and 1994 represent
actual production for the periods November 1994 through April 1995 and
November 1993 through April 1994, respectively.
-14-
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.)
SEC FILE OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
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)
-15-
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
(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 1995.
-16-
<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
Vice President
and Trust Officer
Date: August 10, 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.
-17-
<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 JUN-30-1995 AND THE
STATEMENT OF DISTRIBUTABLE INCOME FOR THE SIX MONTHS ENDED JUN-30-1995 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS
</LEGEND>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> JUN-30-1995
<CASH> 1,154,478
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,154,478
<PP&E> 28,267,655
<DEPRECIATION> 27,035,298
<TOTAL-ASSETS> 2,386,835
<CURRENT-LIABILITIES> 185,448
<BONDS> 0
<COMMON> 0
0
0
<OTHER-SE> 1,232,357
<TOTAL-LIABILITY-AND-EQUITY> 2,386,835
<SALES> 0
<TOTAL-REVENUES> 654,067
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 400,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 254,067
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 254,067
<EPS-PRIMARY> .053
<EPS-DILUTED> .053
<PAGE>
</TABLE>
