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, 1996
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _____________________
TO ______________________
COMMISSION FILE NUMBER 0-6910
------------------------
TEL OFFSHORE TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-6004064
(STATE OF INCORPORATION (I.R.S. EMPLOYER
OR ORGANIZATION) IDENTIFICATION NO.)
TEXAS COMMERCE BANK
NATIONAL ASSOCIATION
CORPORATE TRUST DIVISION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL (ZIP CODE)
EXECUTIVE OFFICES)
Registrant's Telephone Number, Including Area Code: (713) 216-5712
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
As of August 1, 1996 -- 4,751,510 Units of Beneficial Interest in TEL
Offshore Trust.
<PAGE>
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-Q are forward-looking
statements. Although the Working Interest Owners have advised the Trust that
they believe that the expectations reflected in the forward-looking statements
contained herein are reasonable, no assurance can be given that such
expectations will prove to have been correct. Important factors that could cause
actual results to differ materially from expectations ("Cautionary Statements")
are disclosed in this Form 10-Q, including without limitation in conjunction
with the forward-looking statements included in this Form 10-Q. All subsequent
written and oral forward-looking statements attributable to the Trust or persons
acting on its behalf are expressly qualified in their entirety by the Cautionary
Statements.
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,
-------------------------- --------------------------
1996 1995 1996 1995
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Royalty income.......................... $ 0 $ 377,894 $ 0 $ 640,363
Interest income......................... 8,622 7,554 17,309 13,704
------------ ------------ ------------ ------------
8,622 385,448 17,309 654,067
Decrease (increase) in reserve for
future Trust expenses................. 113,821 (80,792) 284,917 (161,356)
General and administrative expenses..... (122,443) (119,208) (302,226) (238,644)
------------ ------------ ------------ ------------
Distributable income.................... $ 0 $ 185,448 $ 0 $ 254,067
============ ============ ============ ============
Distributions per Unit (4,751,510
Units)................................ $ 0 $ .039029 $ 0 $ .053470
============ ============ ============ ============
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
JUNE 30, DECEMBER 31,
1996 1995
----------- ------------
(UNAUDITED)
ASSETS
Cash and cash equivalents............... $ 893,015 $1,261,606
Net overriding royalty interest in
producing oil and gas properties net
of accumulated amortization of
$27,196,037 and $27,196,037,
respectively.......................... 1,071,618 1,071,618
----------- ------------
Total assets............................ $ 1,986,863 $2,333,224
=========== ============
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders.... $ 0 $ 83,674
Reserve for future Trust expenses....... 893,015 1,177,932
Commitments and contingencies (Note 6)
Trust corpus (4,751,510 Units of
beneficial interest authorized and
outstanding).......................... 1,071,618 1,071,618
----------- ------------
Total liabilities and Trust corpus...... $ 1,986,863 $2,333,224
=========== ============
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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- --------------------------
1996 1995 1996 1995
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period.... $ 1,071,618 $ 1,303,796 $ 1,071,618 $ 1,343,475
Distributable income................. 0 185,448 0 254,067
Distributions payable to Unit
holders............................ 0 (185,448) 0 (254,067)
Amortization of net overriding
royalty interest................... 0 (71,439) 0 (111,118)
------------ ------------ ------------ ------------
Trust corpus, end of period.......... $ 1,071,618 $ 1,232,357 $ 1,071,618 $ 1,232,357
============ ============ ============ ============
</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 (the
"Conveyance"). The dissolution of Exploration I had no impact on future cash
distributions to Unit holders.
On November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired most of the
Gulf of Mexico offshore oil and gas properties of Tenneco, including all the
Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as
the Working Interest Owner and Managing General Partner of the Partnership.
Chevron also assumed Tenneco's obligations under the Conveyance.
On October 30, 1992, 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 were 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 was 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.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from Pennzoil. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
Pennzoil. As a result of such acquisitions, SONAT and Amoco have replaced
Pennzoil as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, and also have assumed Pennzoil's
obligations under the Conveyance with respect to such properties.
Chevron remains the Managing General Partner of the Partnership. All of the
Royalty Properties continue to be subject to the Royalty, and the Trust and the
Partnership, in general, continue to operate as if the above-described sales of
the Royalty Properties had not occurred.
Unless the context in which such terms are used indicates otherwise, in
these Notes the terms "Working Interest Owner" and "Working Interest Owners"
generally refer to the owner or owners of the
3
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
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 from October 30, 1992
until October 1, 1995 and with respect to Eugene Island 348 and Eugene Island
208 thereafter; Texaco with respect to West Cameron 643 for periods beginning on
or after December 1, 1994; SONAT with respect to East Cameron 354 for periods
beginning on or after October 1, 1995; and Amoco with respect to Eugene Island
367 for periods beginning on or after October 1, 1995).
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, 1995.
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income is recorded when received by the Corporate Trustee
on the last business day of each calendar quarter; and
(b) Trust general and administrative expenses are recorded when paid,
except for the cash reserved for future general and
administrative expenses, as discussed in Note 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, which is calculated based on units-of-production and current
royalty income in relation to estimated future royalty income, 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.
Effective January 1, 1996, the Trust adopted Statement of Financial
Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The adoption of
SFAS 121 did not have a material impact on the financial position or
distributable income of the Trust.
4
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
NOTE 3 -- OVERRIDING ROYALTY INTEREST
The Royalty entitles the Trust to its share (99.99%) of 25% of the Net
Proceeds attributable to the Royalty Properties. The Conveyance, dated January
1, 1983, provides that the Working Interest Owners will calculate, for each
period of three months commencing the first day of February, May, August and
November, an amount equal to 25% of the Net Proceeds from their oil and gas
properties for the period. Generally, Net Proceeds are the amounts received by
the Working Interest Owners from the sale of minerals from the Royalty
Properties less operating and capital costs incurred, management fees and
expense reimbursements owing the Managing General Partner of the Partnership,
applicable taxes other than income taxes, and cash escrows. Cash escrows are for
the future costs to be incurred to plug and abandon wells, dismantle and remove
platforms, pipelines and other production facilities, and for the estimated
amount of future capital expenditures on the Royalty Properties. Net Proceeds do
not include amounts received by the Working Interest Owners as advance gas
payments, "take-or-pay" payments or similar payments unless and until such
payments are extinguished or repaid through the future delivery of gas.
NOTE 4 -- DISTRIBUTIONS TO UNIT HOLDERS
In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust are distributed currently to the Unit holders. The
amounts distributed are determined on a quarterly basis and are payable to Unit
holders of record as of the last business day of each calendar quarter. However,
cash distributions are made in January, April, July and October and include
interest earned from the quarterly record date to the date of distribution.
NOTE 5 -- SPECIAL COST ESCROW
The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the Royalty Properties, as well as for the estimated amount of
future drilling projects and other capital expenditures on the Royal Properties.
As provided in the Conveyance, the amount of funds to be reserved is determined
based on factors including estimates of aggregate future production costs,
aggregate future Special Costs, aggregate future net revenues and actual current
net proceeds. Deposits into this account reduce current distributions and are
placed in an escrow account and invested in short-term certificates of deposit.
Such account is herein referred to as the "Special Cost Escrow Account."
Deposits to the Special Cost Escrow Account will generally be made when the
balance in the Special Cost Escrow Account is less than 125% of future Special
Costs and there is a Net Revenues Shortfall (a calculation of the excess of
estimated future costs over estimated future net revenues pursuant to a formula
contained in the Conveyance). When there is not a Net Revenues Shortfall,
amounts in the Special Cost Escrow Account will generally be released, to the
extent that Special Costs have been incurred. Amounts in the Special Cost Escrow
Account generally will also be released when the balance in such account exceeds
125% of future Special Costs. In the first six months of 1995, a net deposit of
approximately $97,200 was made by the Trust into the Special Cost Escrow
Account. The deposit was primarily a result of an increase in the estimates of
projected capital expenditures on the Royalty Properties. In the first six
months of 1996, there was also a deposit of funds into the Special Cost Escrow
Account. The Trust's share of the funds deposited was approximately $1,321,000.
The deposit was primarily a result of an increase in the current estimates of
projected capital expenditures, production costs
5
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
and abandonment costs in connection with the Ship Shoal 182/183 drilling. As of
June 30, 1996, approximately $3,893,000 remained in the Special Cost Escrow
Account.
Capital expenditures and drilling programs by the Working Interest Owners,
such as those discussed under "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in this Form 10-Q, can have a significant
impact on the amount of deposits into the Special Cost Escrow account. Such
deposits can result in a significant reduction in royalty income in the periods
in which such deposits are made, including the possibility that no royalty
income would be received in such periods.
NOTE 6 -- EXPENSE RESERVE
At December 31, 1991, a cash reserve of $120,000 had been established for
future Trust general and administrative expenses. During 1992 and 1993, in
anticipation of future periods when the cash received from the Royalty may not
be sufficient for payment of Trust expenses, the reserve for future Trust
general and administrative expenses was increased each quarter by an amount
equal to the difference between $150,000 and the amount of the Trust's general
and administrative expenses for such quarter. In 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 $122,400 in the second quarter of 1996. In this quarter, the Trust
had no royalty income and interest income of approximately $8,600; therefore,
the Trust's cash reserve was decreased by approximately $113,800 to pay these
expenses, reducing the total amount of the Trust's cash reserve at June 30, 1996
to $893,015.
NOTE 7 -- 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 $160,200 has been recovered from the Trust by the Working Interest
Owner through the second quarter of 1996, 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.
6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FINANCIAL REVIEW
THREE MONTHS ENDED JUNE 30, 1996 AND 1995
The Trust had no royalty income for the three months ended June 30, 1996;
therefore, no distribution was made. Distributions to Unit holders for the three
months ended June 30, 1995 amounted to $185,448 or $.039029 per Unit. The lack
of royalty income for the second quarter of 1996 was due primarily to a larger
deposit of funds into the Special Cost Escrow Account (discussed below) in the
second quarter of 1996, as compared to the second quarter of 1995.
Gas revenues increased approximately 206% in the second quarter of 1996
compared to the second quarter of 1995 primarily due to an 83% increase in gas
volumes, which increase was primarily attributable to a successful sidetrack
well on the West Cameron 643 property. In addition, there was a 74% increase in
the average price received for natural gas from $1.55 per Mcf in the second
quarter of 1995 to $2.70 per Mcf in the second quarter of 1996. Crude oil
revenues increased approximately 44% in the second quarter of 1996 in comparison
to the same period in 1995 primarily due to a 30% increase in crude oil and
condensate volumes from the 1995 second quarter to the 1996 second quarter. This
increase in crude oil and condensate volumes was primarily attributable to
increased volumes on the Eugene Island 339 property. In addition, there was an
11% increase in the average price received from $16.66 per barrel in the second
quarter of 1995 to $18.49 per barrel in the second quarter of 1996. The Trust's
share of capital expenditures increased by approximately $546,500 in the second
quarter of 1996 as compared to the same period in 1995 due primarily to expenses
incurred on the F-2 well drilling on the Ship Shoal 182/183 property in the
first quarter of 1996. The Trust's share of operating expenses increased by
approximately $102,000 in the second quarter of 1996 as compared to the same
period in 1995 due primarily to a compressor repair on the Ship Shoal 182/183
property in the second quarter of 1996.
In the second quarter of 1996, there was undistributed net income of
$483,963. Undistributed net income represents positive Net Proceeds generated
during the period that were applied to an existing loss carryforward. As of June
30, 1996, the loss carryforward was $2,463,260 ($615,815 net to the Trust). This
loss carryforward relates primarily to the Eugene Island 348 gas imbalance
settlement in 1994.
In the second quarter of 1996, there was a deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $316,000, compared to a deposit of funds into the Special Cost
Escrow Account of $37,931 in the second quarter of 1995. 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.)
SIX MONTHS ENDED JUNE 30, 1996 AND 1995
The Trust had no royalty income for the six months ended June 30, 1996;
therefore, no distribution was made. Distributions to Unit holders for the six
months ended June 30, 1995 amounted to $254,067 or $.053470 per Unit. The lack
of royalty income for the first six months of 1996 was due primarily to a larger
deposit of funds into the Special Cost Escrow Account (discussed below) in the
first six months of 1996, as compared to the first six months of 1995.
Gas revenues increased approximately 109% in the first six months of 1996
as compared to the first six months of 1995 primarily due to a 55% increase in
the average price received for natural gas from $1.68 per Mcf in the first six
months of 1995 to $2.60 per Mcf in the first six months of 1996. In addition,
there was a 39% increase in gas volumes. This increase in gas volumes was
primarily attributable to a successful sidetrack well on the West Cameron 643
property in the second quarter of 1996. Crude oil revenues
7
increased approximately 114% in the first six months of 1996 as compared to the
same period in 1995 primarily due to a 109% increase in crude oil and condensate
volumes. The increase in volumes was primarily attributable to a well adjustment
on the B-13 well of 187,000 barrels on the Eugene Island 339 property in the
first quarter of 1996. In addition, there was an increase in the average price
received from $16.12 per barrel in the first six months of 1995 to $16.47 per
barrel in the first six months of 1996. The Trust's share of capital
expenditures increased by approximately $920,250 in the first six months of 1996
as compared to the same period in 1995 due primarily to six workovers on the
West Cameron 643 property and to drilling the F-2 well on the Ship Shoal 182/183
property in the first quarter of 1996. The Trust's share of operating expenses
increased by approximately $94,500 in the first six months of 1996 as compared
to the same period in 1995 due primarily to a compressor repair on the Ship
Shoal 182/183 property in the first quarter of 1996.
In the first six months of 1996, there was an undistributed net loss of
$292,568. Undistributed net loss represents negative Net Proceeds generated
during the period that are carried forward and offset in future periods by
positive Net Proceeds. The undistributed net loss in the first six months of
1996 was primarily related to costs associated with six well workovers on the
West Cameron 643 property in the first quarter of 1996.
In the first six months of 1996 there was a net deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $1,321,000. During the first six months of 1995, there was a
deposit of funds into the Special Cost Escrow Account. The Trust's share of the
funds deposited was approximately $97,224. (For additional information relating
to the Special Cost Escrow see page 11 of this Form 10-Q.)
RESERVE FOR FUTURE TRUST EXPENSES
In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. During
1992 and 1993, in anticipation of future periods when the cash received from the
Royalty may not be sufficient for payment of Trust expenses, the reserve for
future Trust general and administrative expenses was increased each quarter by
an amount equal to the difference between $150,000 and the amount of the Trust's
general and administrative expenses for such quarter. In 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 $122,400 in the second quarter of 1996. In this quarter, the Trust
had no royalty income and interest income of approximately $8,600; therefore,
the Trust's cash reserve was decreased by approximately $113,800 to pay these
expenses, reducing the total amount of the Trust's cash reserve at June 30, 1996
to $893,015.
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.
8
OPERATIONAL REVIEW
THREE MONTHS ENDED JUNE 30, 1996 AND 1995
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY
THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 gas revenues increased from $32,245 in the second
quarter of 1995 to $220,506 in the second quarter of 1996, primarily due to an
increase in gas volumes. Gas volumes increased from 18,777 Mcf in the second
quarter of 1995 to 80,014 Mcf in the second quarter of 1996 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 an increase in the average
natural gas sales price for Ship Shoal 182/183 from $1.72 per Mcf in the second
quarter of 1995 to $2.92 per Mcf in the same period of 1996. The majority of the
gas from this property is being purchased by Tennessee Gas Pipeline Company
("Tennessee Gas") at a calculated monthly price based on the spot market rate.
In addition, the Working Interest Owner has advised the Trust that approximately
61,400 Mcf have been overtaken by the Working Interest Owner from this property
as of April 30, 1996. The Trust's share of this overtake position is
approximately 15,350 Mcf. Accordingly, gas revenues from this property may be
reduced in future periods while underproduced parties recover their share of the
gas imbalance. A decrease in crude oil production from 60,950 barrels in the
second quarter of 1995 to 52,023 barrels in the second quarter of 1996 and an
increase in the average crude oil price from $16.73 per barrel in the second
quarter of 1995 to $18.65 per barrel for the same period in 1996 resulted in a
decrease in crude oil revenues from $1,019,818 in the second quarter of 1995 to
$970,071 in the second quarter of 1996. The decrease in crude oil production was
primarily due to a continued natural production decline on this property.
Operating expenses increased from $325,601 in the second quarter of 1995 to
$492,815 in the second quarter of 1996 due primarily to a compressor repair in
the second quarter of 1996. Capital expenditures increased from $1,368 in the
second quarter of 1995 to $1,307,815 in the second quarter of 1996 due primarily
to the drilling of the F-2 delineation gas well on this property in the first
quarter of 1996. The completed well cost is estimated at approximately $2.0
million ($492,000 net to the Trust). The F-2 well was shut in during the second
quarter of 1996 for repairs. In addition, the Working Interest Owner has advised
the Trust that in the second quarter of 1996 it began drilling the B-11 and the
B-12 developmental oil wells on this property. Completion of the B-11 and the
B-12 wells is expected to occur in the third quarter of 1996. The Working
Interest Owner has advised the Trust that it plans to drill a third
developmental oil well in August 1996. The estimated cost of drilling the three
developmental oil wells on this property is $8.5 million ($2.1 million net to
the Trust). Production on the B-11 and B-12 wells is scheduled to begin in
September 1996.
Eugene Island 339 gas revenues increased from $299,836 in the second
quarter of 1995 to $454,921 in the second quarter of 1996 due primarily to an
increase in the average price received for natural gas from $1.62 per Mcf in the
second quarter of 1995 to $3.02 per Mcf in the second quarter of 1996. The
increase in average price was partially offset by a decrease in gas volumes from
174,532 Mcf in the second quarter of 1995 to 148,975 Mcf for the same period in
1996. The decrease in gas volumes was primarily due to a continued natural
production decline on this property. The Working Interest Owner has advised the
Trust that there is an overtake imbalance position of approximately 307,700 Mcf
on this property as of April 30, 1996. The Trust's share of this overtake
position is approximately 76,925 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 $974,938 in the second quarter of 1995 to $1,943,120 in
the second quarter of 1996 due primarily to an increase in volumes from 58,769
barrels in the second quarter of 1995 to 105,534 barrels for the same period in
1996. The increase in volumes was primarily due to volumes on the
9
B-13 well being understated in 1995. The B-13 well adjustment was made in the
first quarter of 1996. In addition, there was an increase in the average price
received for crude oil and condensate from $16.59 per barrel in the second
quarter of 1995 to $18.41 per barrel in the second quarter of 1996. Operating
expenses decreased from $413,234 in the second quarter of 1995 to $324,399 in
the second quarter of 1996 due primarily to a reduction in environmental
compliance costs. The Working Interest Owner has advised the Trust that it
intends to pursue drilling on this property in 1997 if drilling on nearby
non-Trust properties in 1996 is successful.
West Cameron 643 gas revenues increased from $161,104 in the second quarter
of 1995 to $1,608,803 in the second quarter of 1996 due primarily to an increase
in gas volumes. Gas volumes increased from 110,177 Mcf in the second quarter of
1995 to 620,259 Mcf in the second quarter of 1996 primarily due to the
successful B-8 sidetrack well drilled on this property in the second quarter of
1996. In addition, there was an increase in the average price received for
natural gas from $1.46 per Mcf in the second quarter of 1995 to $2.59 per Mcf
for the same period in 1996. Capital expenditures increased from $2,806 in the
second quarter of 1995 to $890,299 in the second quarter of 1996 due primarily
to costs associated with workovers on the A-2 and A-9 wells on this property in
the first quarter of 1996. The Working Interest Owner has advised the Trust that
in the second quarter of 1996 the B-5, B-8 and B-9 wells were drilled on this
property at an aggregate cost of $5.7 million ($1.4 million net to the Trust).
The Working Interest Owner has advised the Trust that as a result of this
drilling, its estimates of proved reserves on this property have increased by
approximately 12,000 barrels of crude oil and condensate (3,000 barrels net to
the Trust) and 9,600,000 Mcf of gas (2,400,000 Mcf net to the Trust). In
addition, the Working Interest Owner has advised the Trust that it plans to
drill an exploratory well on this property in the third quarter of 1996 at an
estimated cost of approximately $584,000 ($146,000 net to the Trust). The
Working Interest Owner has advised the Trust that some of the future income from
production on these new wells may be offset significantly by accrued expenses
and Special Cost Escrow deposits related to such wells.
SIX MONTHS ENDED JUNE 30, 1996 AND 1995
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY
THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 gas revenues increased from $234,134 in the first six
months of 1995 to $452,833 in the first six months of 1996, primarily due to the
increase in the average natural gas sales price from $1.74 per Mcf in the first
six months of 1995 to $2.84 per Mcf in the same period of 1996. In addition,
there was an increase in the gas volumes from 133,583 Mcf in the first six
months of 1995 to 165,437 Mcf in the first six months of 1996 due primarily to
the C-10 well being watered out and the C-4 well being sanded in throughout the
second quarter of 1995. A decrease in crude oil production from 131,690 barrels
in the first six months of 1995 to 107,996 barrels in the first six months of
1996 and an increase in the average crude oil price from $16.25 per barrel in
the first six months of 1995 to $17.33 per barrel for the same period in 1996
resulted in a decrease in crude oil revenues from $2,140,011 in the first six
months of 1995 to $1,871,528 in the first six months of 1996. The decrease in
crude oil production was primarily due to a continued natural production decline
on this property. Operating expenses increased from $614,243 in the first six
months of 1995 to $790,594 in the first six months of 1996 due primarily to a
compressor repair in the second quarter of 1996. Capital expenditures increased
from $36,972 in the first six months of 1995 to $1,974,279 for the same period
in 1996 due primarily to the drilling of the F-2 delineation gas well on this
property in the first quarter of 1996.
Eugene Island 339 gas revenues increased from $710,587 in the first six
months of 1995 to $805,359 in the first six months of 1996 due primarily to an
increase in the average price received for natural gas from $1.79 per Mcf in the
first six months of 1995 to $2.73 per Mcf for the same period in 1996. The
increase in the average price received was partially offset by a decrease in gas
volumes from 381,282 Mcf in the first
10
six months of 1995 to 294,744 Mcf in the first six months of 1996. The decrease
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) in favor of
the Working Interest Owner on this property in the first quarter of 1995 and a
continued natural production decline on this property. Crude oil revenues
increased from $1,448,692 in the first six months of 1995 to $5,910,665 in the
first six months of 1996 due primarily to an increase in volumes from 90,826
barrels in the first six months of 1995 to 364,522 barrels for the same period
in 1996. The increase in volumes was primarily attributable to the wells being
temporarily shut in on this property in the first quarter of 1995 and to volumes
being understated in 1995 on the B-13 well. The B-13 well adjustment was made in
the first quarter of 1996. In addition, there was an increase in the average
price received for crude oil and condensate from $15.95 per barrel in the first
six months of 1995 to $16.21 per barrel for the same period in 1996. Operating
expenses decreased from $846,596 in the first six months of 1995 to $614,672 in
the first six months of 1996 due primarily to a reduction in environmental
compliance costs and a service facilities credit on this property in the first
quarter of 1996.
West Cameron 643 gas revenues increased from $414,586 in the first six
months of 1995 to $2,041,628 in the first six months of 1996 primarily due to an
increase in gas volumes. Gas volumes increased from 252,768 Mcf in the first six
months of 1995 to 803,814 Mcf for the same period in 1996 primarily due to
successful workovers on the A-2 and A-9 wells in the first quarter of 1996 and
the successful drilling of the B-8 sidetrack well during the second quarter of
1996. In addition, there was an increase in the average price received for
natural gas from $1.64 per Mcf in the first six months of 1995 to $2.54 per Mcf
in the first six months of 1996. Capital expenditures increased from $244,497 in
the first six months of 1995 to $1,951,892 for the same period in 1996 due
primarily to costs associated with workovers on the A-2, A-6, A-9, A-10, A-16
and B-3 wells on this property in the first quarter of 1996.
FUTURE NET REVENUES AND TERMINATION OF THE TRUST
Based on a reserve study provided to the Trust by DeGolyer and MacNaughton,
independent petroleum engineers, it was estimated that as of October 31, 1995
future net revenues attributable to the Trust's royalty interests approximated
$7.7 million. Such reserve study also indicates that approximately 70% of the
future net revenues from the Royalty Properties are expected to be received by
the Trust during the next 4 years. In addition, because the Trust will terminate
in the event estimated future net revenues fall below $2 million, it would be
possible for the Trust to terminate even though some or all of the Royalty
Properties continued to have remaining productive lives. Upon termination of the
Trust, the Trustees will sell for cash all of the assets held in the Trust
estate and make a final distribution to Unit holders of any funds remaining
after all Trust liabilities have been satisfied. The estimates of future net
revenues discussed above are subject to large variances from year to year and
should not be construed as exact. There are numerous uncertainties present in
estimating future net revenues for the Royalty Properties. The estimate may vary
depending on changes in market prices for crude oil and natural gas, the
recoverable reserves, annual production and costs assumed by DeGolyer and
MacNaughton. In addition, future economic and operating conditions as well as
results of future drilling plans may cause significant changes in such estimate.
The discussion set forth above is qualified in its entirety by reference to the
Trust's 1995 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 Royalty Properties, as well as for the estimated amount of
future drilling projects and other capital expenditures on the Royalty
Properties. As provided in the Conveyance, the amount of funds to be reserved is
determined based on factors including estimates of aggregate future production
costs, aggregate future Special Costs, aggregate future
11
net revenues and actual current net proceeds. Deposits into this account reduce
current distributions and are placed in an escrow account and invested in
short-term certificates of deposit. Such account is herein referred to as the
"Special Cost Escrow Account." The Trust's share of interest generated from the
Special Cost Escrow Account serves to reduce the Trust's share of allocated
production costs. Special Cost Escrow funds will generally be utilized to pay
Special Costs to the extent there are not adequate current net proceeds to pay
such costs. Special Costs that have been paid are no longer included in the
Special Cost Escrow calculation. Deposits to the Special Cost Escrow Account
will generally be made when the balance in the Special Cost Escrow Account is
less than 125% of future Special Costs and there is a Net Revenues Shortfall (a
calculation of the excess of estimated future costs over estimated future net
revenues pursuant to a formula contained in the Conveyance). When there is not a
Net Revenues Shortfall, amounts in the Special Cost Escrow Account will
generally be released, to the extent that Special Costs have been incurred.
Amounts in the Special Cost Escrow Account generally will also be released when
the balance in such account exceeds 125% of future Special Costs. In the first
six months of 1995, a net deposit of approximately $97,200 was made by the Trust
into the Special Cost Escrow Account. The deposit was primarily a result of an
increase in the estimates of projected capital expenditures on the Royalty
Properties. In the first six months of 1996, there was also a deposit of funds
into the Special Cost Escrow Account. The Trust's share of the funds deposited
was approximately $1,321,000. The deposit was primarily a result of an increase
in the current estimates of projected capital expenditures, production costs and
abandonment costs in connection with the Ship Shoal 182/183 drilling. As of June
30, 1996, approximately $3,893,000 remained in the Special Cost Escrow Account.
Capital expenditures and drilling programs by the Working Interest Owners,
such as those discussed under "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in this Form 10-Q, can have a significant
impact on the amount of deposits into the Special Cost Escrow account. Such
deposits can result in a significant reduction in royalty income in the periods
in which such deposits are made, including the possibility that no royalty
income would be received in such periods.
OVERVIEW OF PRODUCTION, PRICES AND NET PROCEEDS
The following schedule provides a summary of the volumes and weighted
average prices for crude oil and condensate and natural gas recorded by the
Working Interest Owners for the Royalty Properties, as well as the Working
Interest Owners' calculations of the net proceeds and the royalties paid to the
Trust during the periods indicated. Net proceeds due to the Trust are calculated
for each three month period commencing on the first day of February, May, August
and November.
12
ROYALTY PROPERTIES
THREE MONTHS ENDED
JUNE 30,(1)
------------------------------
1996 1995
-------------- --------------
Crude oil and condensate (bbls)...... 158,077 121,694
Natural gas and gas products (Mcf)... 897,287 490,437
Crude oil and condensate average
price, per bbl..................... $ 18.49 $ 16.66
Natural gas average price, per Mcf
(excluding gas products)........... $ 2.70 $ 1.55
Crude oil and condensate revenues.... $ 2,922,715 $ 2,027,148
Natural gas and gas products
revenues........................... 2,417,520 790,811
Production expenses.................. (1,383,912) (844,487)
Capital expenditures................. (2,210,228) (24,345)
Undistributed Net Loss (Income)(2)... (483,963) (285,675)
(Provision for) Refund of escrowed
special costs...................... (1,262,132) (151,724)
-------------- --------------
NET PROCEEDS......................... 0 1,511,728
Royalty interest..................... x25% x25%
-------------- --------------
Partnership share.................... 0 377,932
Trust interest....................... x99.99% x99.99%
-------------- --------------
Trust share.......................... $ 0 $ 377,894
============== ==============
- ------------
(1) The amounts for the three months ended June 30, 1996 and 1995 represent
actual production for the periods February 1996 through April 1996 and
February 1995 through April 1995, respectively.
(2) Undistributed net loss represents negative Net Proceeds, generated during
the respective period. An undistributed net loss is carried forward and
offset, in future periods, by positive Net Proceeds earned by the related
Working Interest Owner(s). Undistributed net income represents positive Net
Proceeds, generated during the respective period, that were applied to an
existing loss carryforward. As of June 30, 1996, the loss carryforward was
$2,463,260 ($615,815 net to the Trust).
13
ROYALTY PROPERTIES
SIX MONTHS ENDED JUNE 30,(1)
------------------------------
1996 1995
-------------- --------------
Crude oil and condensate
(bbls)........................... 474,075 226,612
Natural gas and gas products
(Mcf)............................ 1,390,059 999,187
Crude oil and condensate average
price, per bbl................... $ 16.47 $ 16.12
Natural gas average price, per
Mcf (excluding gas products)..... $ 2.60 $ 1.68
Crude oil and condensate
revenues......................... $ 7,808,076 $ 3,653,812
Natural gas and gas products
revenues......................... 3,607,889 1,726,988
Production expenses.............. (2,410,962) (1,767,467)
Capital expenditures............. (4,011,591) (330,613)
Undistributed Net Loss
(Income)(2)...................... 292,568 (332,156)
(Provision for) Refund of
escrowed special costs........... (5,285,980) (388,856)
-------------- --------------
NET PROCEEDS..................... 0 2,561,708
Royalty interest................. x25% x25%
-------------- --------------
Partnership share................ 0 640,427
Trust interest................... x99.99% x99.99%
-------------- --------------
Trust share...................... $ 0 $ 640,363
============== ==============
- ------------
(1) The amounts for the six months ended June 30, 1996 and 1995 represent actual
production for the periods November 1995 through April 1996 and November
1994 through April 1995, respectively.
(2) Undistributed net loss represents negative Net Proceeds, generated during
the respective period. An undistributed net loss is carried forward and
offset, in future periods, by positive Net Proceeds earned by the related
Working Interest Owner(s). Undistributed net income represents positive Net
Proceeds, generated during the respective period, that were applied to an
existing loss carryforward. As of June 30, 1996, the loss carryforward was
$2,463,260 ($615,815 net to the Trust).
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)
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 1996.
15
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/ MICHAEL J. ULRICH
--------------------------
MICHAEL J. ULRICH
SENIOR VICE PRESIDENT AND
TRUST OFFICER
Date: August 9, 1996
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.
16
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM THE STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS AS OF JUNE-30-1996
AND THE STATEMENT OF DISTRIBUTABLE INCOME FOR THE SIX MONTHS ENDED JUNE-30-1996
AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1996
<CASH> 893,015
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 893,015
<PP&E> 28,267,655
<DEPRECIATION> 27,196,037
<TOTAL-ASSETS> 1,986,863
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 1,071,618
<TOTAL-LIABILITY-AND-EQUITY> 1,986,863
<SALES> 0
<TOTAL-REVENUES> 17,309
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 302,226
<LOSS-PROVISION> (284,917)
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 0
<EPS-PRIMARY> .000
<EPS-DILUTED> .000
</TABLE>
