SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
[ ] 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 OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
CHASE BANK OF TEXAS
NATIONAL ASSOCIATION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 216-5712
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
NONE NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
UNITS OF BENEFICIAL INTEREST
(TITLE OF CLASS)
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 by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the 4,751,510 Units of Beneficial Interest in
TEL Offshore Trust held by non-affiliates of the registrant at the closing sales
price on March 20, 1998, of $5.3125 was $25,242,396.88.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
As of March 20, 1998, 4,751,510 Units of Beneficial Interest in TEL
Offshore Trust.
Documents Incorporated By Reference: None
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TABLE OF CONTENTS
PART I
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PAGE
Item 1. Business........................................................................................ 1
Description of the Trust........................................................................ 1
General......................................................................................... 3
History of the Trust............................................................................ 5
Description of the Units........................................................................ 5
Distributions................................................................................... 5
Possible Requirement that Units be Divested..................................................... 6
Liability of Unit Holders....................................................................... 6
Federal Income Tax Matters...................................................................... 8
Tax-Exempt Organizations........................................................................ 8
State Law Considerations........................................................................ 8
Termination of the Trust........................................................................ 9
Royalty Income, Distributable Income and Total Assets........................................... 9
Description of Royalty Properties............................................................... 9
Producing Acreage and Wells..................................................................... 10
Reserves........................................................................................ 18
Operations and Production....................................................................... 18
Marketing....................................................................................... 18
Gas Marketing................................................................................... 19
Oil Marketing................................................................................... 20
Competition and Regulation...................................................................... 20
Competition..................................................................................... 20
Regulation -- General........................................................................... 22
Environmental Regulations....................................................................... 24
Item 2. Properties...................................................................................... 24
Item 3. Legal Proceedings............................................................................... 24
Item 4. Submission of Matters to a Vote of Security Holders............................................. 24
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters....................... 25
Item 6. Selected Financial Data......................................................................... 25
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.................................................................................... 25
Item 8. Financial Statements and Supplementary Data..................................................... 32
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.................................................................................... 43
PART III
Item 10. Directors and Executive Officers of the Registrant.............................................. 44
Item 11. Executive Compensation.......................................................................... 44
Item 12. Security Ownership of Certain Beneficial Owners and Management.................................. 44
Item 13. Certain Relationships and Related Transactions.................................................. 44
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................ 45
SIGNATURES................................................................................................. 46
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NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K 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-K 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-K, including without limitation in
conjunction with the forward-looking statements included in this Form 10-K. 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.
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PART I
ITEM 1. BUSINESS.
DESCRIPTION OF THE TRUST
GENERAL
The TEL Offshore Trust ("Trust"), created under the laws of the State of
Texas, maintains its offices at the office of the Corporate Trustee, Chase Bank
of Texas, National Association (formerly known as Texas Commerce Bank National
Association) ("Corporate Trustee"), 712 Main Street, Houston, Texas 77002. The
telephone number of the Trust is 713-216-5712. George Allman, Jr., W. Leslie
Duffy and Richard L. Melton serve as individual trustees ("Individual
Trustees") of the Trust. The Individual Trustees and the Corporate Trustee may
hereinafter collectively be referred to as Trustees.
The principal asset of the Trust consists of a 99.99% interest in the TEL
Offshore Trust Partnership ("Partnership"). Chevron U.S.A. Inc. ("Chevron")
owns the remaining .01% interest in the Partnership. The Partnership owns an
overriding royalty interest ("Royalty"), equivalent to a 25% net profits
interest, in certain oil and gas properties (the "Royalty Properties") located
offshore Louisiana.
On November 18, 1988, Chevron acquired most of the Gulf of Mexico offshore
oil and gas properties of Tenneco Oil Company ("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 instrument conveying the
Royalty to the Partnership (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 replaced Pennzoil as
the Working Interest Owners of the East Cameron 354 and Eugene Island 367
properties, respectively, on October 1, 1995, and also assumed Pennzoil's
obligations under the Conveyance with respect to such properties.
Effective January 1, 1998 Energy Resource Technology, Inc. ("Energy")
acquired the East Cameron 354 property from SONAT. As a result of such
acquisition, Energy replaced SONAT as the Working Interest Owner of the East
Cameron 354 property effective January 1, 1998, and also assumed SONAT's
obligations under the Conveyance with respect to such property.
Chevron remains the Managing General Partner of the Partnership. The
Royalty Properties continue to be subject to the Royalty, and the Trust and
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, the
terms "Working Interest Owner" and "Working Interest Owners" as used herein
generally refer to the owner or owners of the Royalty Properties (Tenneco
Exploration, Ltd. 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
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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 from October 1, 1995 until January 1, 1998; Amoco with
respect to Eugene Island 367 for periods beginning on or after October 1, 1995;
and Energy with respect to East Cameron 354 for periods beginning on or after
January 1, 1998).
A total of 4,751,510 units of beneficial interest in the Trust ("Units")
are issued and outstanding. On October 22, 1996, the Trust Units were delisted
from the National Association of Securities Dealers Automated Quotation System
("NASDAQ") SmallCap Market. The delisting was a result of a determination by
NASDAQ that the Trust would not be able to sustain long-term compliance with
NASDAQ continued listing standards. The Trust has been advised by NASDAQ that
the Trust Units are being traded on the OTC Bulletin Board. The Trust Units may
also be traded on pink sheets. From inception of the Trust to December 31, 1997,
distributions to Unit holders totaled approximately $74,773,000, or
approximately $15.73 per Unit.
The terms of the TEL Offshore Trust Agreement (the "Trust Agreement")
provide, among other things, that: (1) the Trust is a passive entity whose
activities are generally limited to the receipt of revenues attributable to the
Trust's interest in the Partnership and the distribution of such revenues, after
payment of or provision for Trust expenses and liabilities, to the owners of the
Units; (2) the Trustees may sell all or any part of the Trust's interest in the
Partnership or cause the sale of all or any part of the Royalty by the
Partnership with the approval of a majority of the Unit holders; (3) the
Trustees can establish cash reserves and can borrow funds to pay liabilities of
the Trust and can pledge the assets of the Trust to secure payment of such
borrowings; (4) to the extent cash available for distribution exceeds
liabilities or reserves therefor established by the Trust, the Trustees will
cause the Trust to make quarterly cash distributions to the Unit holders in
January, April, July and October of each year; and (5) the Trust will terminate
upon the first to occur of the following events: (i) total future net revenues
attributable to the Partnership's interest in the Royalty, as determined by
independent petroleum engineers, as of the end of any year, are less than $2
million or (ii) a decision to terminate the Trust by the affirmative vote of
Unit holders representing a majority of the Units. Total future net revenues
attributable to the Partnership's interest in the Royalty were estimated at
$24.3 million as of October 31, 1997. (See "Termination of the Trust" and Note
9 of the Notes to Financial Statements under Item 8 of this Form 10-K for
further information regarding estimated future net revenues.) Upon termination
of the Trust, the Trustees will sell for cash all 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 terms of the Agreement of General Partnership of the Partnership (the
"Partnership Agreement") provide that the Partnership shall dissolve upon the
occurrence of any of the following: (a) December 31, 2030, (b) the election of
the Trust to dissolve the Partnership, (c) the termination of the Trust, (d) the
bankruptcy of the Managing General Partner of the Partnership, (e) the
dissolution of the Managing General Partner or its election to dissolve the
Partnership; provided that the Managing General Partner has agreed not to elect
to dissolve the Partnership.
Under the Conveyance and the Partnership Agreement, the Trust is entitled
to its share (99.99%) of 25% of the Net Proceeds, as hereinafter defined,
realized from the sale of the oil, gas and associated hydrocarbons when produced
from the Royalty Properties. See "Description of Royalty Properties." The
Conveyance provides that the Working Interest Owners will calculate, for each
quarterly period commencing the first day of February, May, August and November,
an amount equal to 25% of the Net Proceeds from its oil and gas properties for
the period. "Net Proceeds" means for each quarterly period, the excess, if
any, of the Gross Proceeds, as hereinafter defined, for such period over
Production Costs, as hereinafter
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defined, for such period. "Gross Proceeds" means the amounts received by the
Working Interest Owners from the sale of oil, gas and associated hydrocarbons
produced from the properties burdened by the Royalty, subject to certain
adjustments. Gross 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. "Production Costs" means, generally, costs incurred on
an accrual basis by the Working Interest Owners in operating the Royalty
Properties, including capital and non-capital costs. In general, Net Proceeds
are computed on an aggregate basis and consist of the aggregate proceeds to the
Working Interest Owners from the sale of oil and gas from the Royalty Properties
less (a) all direct costs, charges and expenses incurred by the Working Interest
Owners in exploration, production, development, drilling and other operations on
the Royalty Properties (including secondary recovery operations); (b) all
applicable taxes (including severance and ad valorem taxes) excluding income
taxes; (c) all operating charges directly associated with the Royalty
Properties; (d) an allowance for costs, computed on a current basis at a rate
equal to the prime rate of The Chase Manhattan Bank (National Association) plus
1/2% on all amounts by which, and for only so long as, costs and expenses for
the Royalty Properties incurred for any quarter have exceeded the proceeds of
production from such Royalty Properties for such quarter; (e) applicable charges
for certain overhead expenses as provided in the Conveyance; (f) the management
fees and expense reimbursements owing the Working Interest Owners; and (g) a
special cost reserve for the future costs to be incurred by the Working Interest
Owners to plug and abandon wells and dismantle and remove platforms, pipelines
and other production facilities from the Royalty Properties and for future
drilling projects and other estimated future capital expenditures on the Royalty
Properties. The Trustees are not obligated to return any royalty income received
in any period, but future amounts otherwise payable shall be reduced by the
amount of any prior overpayments of such royalty income. The Working Interest
Owners are required to maintain books and records sufficient to determine
amounts payable under the Royalty. The Working Interest Owners are also required
to deliver to the Corporate Trustee a statement of the computation of Net
Proceeds no later than the tenth business day prior to the quarterly record
date.
The Royalty Properties are required to be operated in accordance with
standards applicable to a prudent oil and gas operator. The Working Interest
Owners are free to transfer their working interest in any of the Royalty
Properties (burdened by the Royalty) to third parties. The Working Interest
Owners are also free to enter into farm-out agreements whereby a Working
Interest Owner would transfer a portion of its interest (unburdened by the
Royalty) while retaining a lesser interest (burdened by the Royalty) in return
for the transferee's obligation to drill a well on the Royalty Properties. The
Working Interest Owners have the right to abandon any well or lease and upon
termination of any lease, the part of the Royalty relating thereto will be
extinguished. The Royalty Properties are primarily operated by the Working
Interest Owners although certain other parties operate some of the Royalty
Properties.
The discussions of terms of the Trust Agreement, Partnership Agreement and
Conveyance contained herein are qualified in their entirety by reference to the
Trust Agreement, Partnership Agreement and Conveyance themselves, which are
exhibits to this Form 10-K and are available upon request from the Corporate
Trustee.
The Trust has no employees. Administrative functions of the Trust are
performed by the Corporate Trustee.
HISTORY OF THE TRUST
Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the Trust
effective January 1, 1983, pursuant to a Plan of Dissolution ("Plan"), which
was approved by Tenneco Offshore's stockholders on December 22, 1982. In
accordance with the Plan, the assets of Tenneco Offshore were transferred to the
Trust as of January 1, 1983, and Units were exchanged for shares of common stock
of Tenneco Offshore on the basis of one Unit for each share of common stock held
by stockholders of record on January 14, 1983. Additionally, the Partnership was
formed, in which the Trust owned a 99.99% interest and Tenneco owned a .01%
interest. The Partnership was formed solely for the purpose of owning the
Royalty, receiving the proceeds from the Royalty, paying the liabilities and
expenses of the Partnership and disbursing remaining
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revenues to the Trust and the Managing General Partner of the Partnership in
accordance with their interests. The Plan was effected by transferring an
overriding royalty interest equivalent to a 25% net profits interest in the oil
and gas properties of Tenneco Exploration, Ltd. ("Exploration I") located
offshore Louisiana to the Partnership, contributing the common stock of Tenneco
Offshore II Company ("Offshore II") to the Trust, and issuing certificates
evidencing 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 Conveyance. The dissolution of Exploration I had no impact on future
cash distributions to Unit holders.
As discussed above, on November 18, 1988, Chevron replaced Tenneco as the
Working Interest Owner and Managing General Partner of the Partnership and
assumed Tenneco's obligations under the Conveyance. On October 30, 1992,
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 and assumed Chevron's obligations
under the Conveyance with respect to such properties on October 30, 1992. On
December 1, 1994, Texaco acquired one of the Royalty Properies 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 and assumed Chevron's obligations under the Conveyance with respect to
such property on December 1, 1994. On October 1, 1995, SONAT and Amoco acquired
the East Cameron 354 and Eugene Island 367 properties, respectively, from
Pennzoil. As a result of such acquisitions, SONAT and Amoco replaced Pennzoil as
the Working Interest Owners of the East Cameron 354 and Eugene Island 367
properties, respectively, and also assumed Pennzoil's obligations under the
Conveyance with respect to such properties on October 1, 1995. Effective January
1, 1998 Energy acquired the East Cameron 354 property from SONAT. As a result of
such acquisition, Energy replaced SONAT as the Working Interest Owner of the
East Cameron 354 property and also assumed SONAT's obligations under the
Conveyance with respect to such property effective January 1, 1998.
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DESCRIPTION OF THE UNITS
Each Unit is evidenced by a transferable certificate issued by the
Corporate Trustee, which ranks equally as to distributions and has one vote on
any matter submitted to Unit holders. Each Unit represents an undivided interest
in the Trust, which in turn owns a 99.99% interest in the Partnership.
DISTRIBUTIONS
The Trustees distribute the Trust's income pro rata for each calendar
quarter within 10 days after the end of each such quarter. Distributions of the
Trust's income are made to Unit holders of record on the Quarterly Record Date,
which is the last business day of each quarterly period, or such later date as
the Trustees determine is required to comply with legal requirements. The
Trustees determine for each quarterly period the amount available for
distribution. Such amount (the "Quarterly Income Amount") consists of the cash
received from the Royalty during such quarterly period plus any other cash
receipts of the Trust, less the obligations of the Trust paid during such
quarterly period, and adjusted for changes made by the Trust during such quarter
in any cash reserves established for the payment of contingent or future
obligations of the Trust. For a discussion of the cash reserves being
established by the Trust, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources" in Item 7 of this Form 10-K.
Within 90 days of the close of each year, the net federal taxable income of
the Trust for each quarterly period ending in such year is reported by the
Trustees for federal tax purposes to the Unit holder of record to whom the
Quarterly Income Amount was distributed.
POSSIBLE REQUIREMENT THAT UNITS BE DIVESTED
The Trust Agreement imposes no restrictions based on nationality or other
status of the persons or other entities who are eligible to hold Units. However,
the Trust Agreement provides that if at any time the Trust or any of the
Trustees are named as a party in any judicial or administrative or other
governmental proceeding which seeks the cancellation or forfeiture of any
interest in any property located in the United States in which the Trust has an
interest because of the nationality or any other status of any one or more
owners of Units, or if at any time the Trustees in their reasonable discretion
determine that such a proceeding is threatened or likely to be asserted and the
Trust has received an opinion of counsel stating that the party asserting or
likely to assert the claims has a reasonable probability of succeeding in such
claim, the following procedures will be applicable:
(a) The Trustees, in their discretion, may seek from an investment
banking firm to be selected by the Trustees an opinion as to whether it is
in the Trust's best interest for the Trustees to take the actions permitted
by (b)(i) through (iii) below.
(b) The Trustees may take no action with respect to the potential
cancellation or forfeiture or may seek to avoid such cancellation or
forfeiture by the following procedure:
(i) The Trustees will promptly give written notice ("Notice") to
each record owner of Units as to the existence of or probable assertion
of such controversy. The Notice will contain a reasonable summary of
such controversy, will include materials which will permit an owner of
Units to promptly confirm or deny to the Trustees that such owner is a
person whose nationality or other status is or would be an issue in such
a proceeding ("Ineligible Holder") and will constitute a demand to
each Ineligible Holder that he dispose of his Units, to a party who
would not be an Ineligible Holder, within 30 days after the date of the
Notice.
(ii) If an Ineligible Holder fails to dispose of his Units as
required by the Notice, the Trustees will have the right to redeem and
will redeem, during the 90 days following the termination of the 30-day
period specified in the Notice, any Unit not so transferred for a cash
price equal to the mean between the closing bid and ask prices of the
Units in the over-the-counter market or, if the Units are then listed on
a stock exchange, the closing price of the Units on the largest stock
exchange on which the Units are listed, on the last business day prior
to the expiration of the 30-day period stated in the Notice. The
procedures for any such purchase are
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more fully described in the Trust Agreement. The Trustee shall cancel
any Units acquired in accordance with the foregoing procedures thereby
increasing the proportionate interest in the Trust of other holders of
Units.
(iii) The Trustees may, in their sole discretion, cause the Trust
to borrow any amounts required to purchase Units in accordance with the
procedures described above.
LIABILITY OF UNIT HOLDERS
It is the intention of the Working Interest Owners and the Trustees that
the Trust be an "express trust" under the Texas Trust Act. Under Texas law,
beneficiaries of an express trust are not personally liable for the obligations
of the trust, even if the assets of the trust are insufficient to discharge its
obligations. However, it is unclear under Texas law whether the Trust will be
held to constitute an express trust and, if it is not held to be an express
trust, whether the holders of Units would be jointly and severally liable for
the obligations of the Trust as would general partners of a partnership.
Under current judicial decisions, the Federal Energy Regulatory Commission
("FERC") is not considered to be empowered to compel refunds from overriding
royalty interest owners with respect to gas price overcharges. However, future
laws, regulations or judicial decisions might permit the FERC or other
governmental agencies to require such refunds from overriding royalty interest
owners or create filing, reporting or certification obligations with respect to
a trust created for such overriding royalty interest owners. Moreover, other
parties, such as oil or gas purchasers, may be able to instigate private
lawsuits or other legal action to compel refunds from overriding royalty
interest owners with respect to oil or gas pricing overcharges.
The Working Interest Owners have agreed that they will not seek to recover
from the Unit holders the amount of any refunds they are required to make except
out of future revenues payable to the Trust. The Trustees will be liable to the
Unit holders if the Trustees allow any liability to be incurred without taking
any and all action necessary to ensure that such liability will be satisfiable
only out of the Trust assets (regardless of whether the assets are adequate to
satisfy the liability) and will be non-recourse to the Unit holders. However,
the Trustees will not be liable to the Unit holders for state or federal income
taxes or for refunds, fines, penalties or interest relating to oil or gas
pricing overcharges under state or federal price controls. The Trustees will be
indemnified from the Trust assets, to the extent that the Trustees' actions do
not constitute gross negligence, fraud or misconduct.
Each Unit holder should consider, in weighing the possible exposure to
liability in the event the Trust were not classified as an express trust, (a)
the substantial value and passive nature of the Trust assets, (b) the
restrictions on the power of the Trustees to incur liabilities on behalf of the
Trust and (c) the limited activities to be conducted by the Trustees.
FEDERAL INCOME TAX MATTERS
OWNERSHIP OF UNITS
The IRS has ruled that the Trust is a grantor trust and that the
Partnership is a partnership for federal income tax purposes. Thus, the Trust
will incur no federal income tax liability, each Unit holder will be treated as
owning an interest in the Partnership and each Unit holder of record as of the
last business day of each quarter will be allocated a share of the income and
deductions of the Trust, including the Trust's share of the income and
deductions of the Partnership (computed on an accrual basis), for such quarter.
Also, each Unit holder will be entitled to compute cost depletion with respect
to his share of income from the Royalty based on his basis in the Royalty. A
Unit holder will have a basis in the Royalty equal to the basis in his Units.
Unit holders that acquired Units after October 11, 1990, are entitled to
percentage depletion on Royalty income attributable to such Units.
Since the IRS has ruled that the Trust is a grantor trust and that the
Partnership is a partnership for federal income tax purposes, the Trustees will
treat each Unit holder as owning an interest in the Partnership and will report
to the Unit holders in a manner consistent with the Trust Agreement and the
Partnership Agreement, allocating income and deductions of the Partnership and
the Trust for each quarter to the Unit
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holders of record as of the last business day of such quarter. Also, since the
IRS has ruled that the Royalty is a non-operating economic interest giving rise
to income subject to depletion, the Trustees will treat the Royalty as a single
property giving rise to income subject to depletion, although the computation of
depletion will be made by each Unit holder based upon information provided by
the Trustees.
The Tax Reform Act of 1986 made significant changes as to the
classification of certain income and expense items. Royalty income is considered
portfolio income. Since all income from the Partnership is royalty income, this
amount, net of depletion, is portfolio income and, subject to certain exceptions
and transitional rules, such royalty income cannot be offset by losses from
passive businesses. Additionally, interest income is portfolio income.
Administrative expense is an investment expense.
BACKUP WITHHOLDING
Distributions from the Trust are generally subject to backup withholding at
a rate of 31% of such distributions. Backup withholding will not normally apply
to distributions to a Unit holder, however, unless such Unit holder fails to
properly provide to the Trust his taxpayer identification number ("TIN") or
the IRS notifies the Trust that the TIN provided by such Unit holder is
incorrect.
SALE OF UNITS
Generally, except for recapture items, the sale, exchange or other
disposition of a Unit will result in capital gain or loss measured by the
difference between the basis in the Unit and the amount realized. Such gain or
loss would be capital gain or loss if such Unit was held by the Unit holder as a
capital asset. For units sold on or prior to May 6, 1997, such capital gain will
be long-term if such Unit holder's holding period exceeded one year as of the
date of sale or exchange. The Taxpayer Relief Act of 1997 reduced the maximum
capital gains rate to 20% for capital assets sold after May 6, 1997, but the
holding period necessary to qualify for the reduced rate increased to eighteen
months effective for sales after July 28, 1997. A special "mid-term" rate
(generally 28%) applies to capital assets sold after July 28, 1997 with a
holding period of over one year but not over eighteen months. Effective for
property placed in service after December 31, 1986, the amount of gain, if any,
realized upon the disposition of oil and gas property is treated as ordinary
income to the extent of the intangible drilling and development costs incurred
with respect to the property and depletion claimed with respect to such property
to the extent it reduced the taxpayer's basis in the property. Depletion
attributable to a positive Section 743(b) basis adjustment of a Unit acquired
after 1986 will also be subject to recapture as ordinary income upon disposition
of the Unit or upon disposition of the oil and gas property to which the
depletion is attributable. The balance of any gain or any loss will be capital
gain or loss if such Unit was held by the Unit holder as a capital asset.
FOREIGN UNIT HOLDERS
In general, a Unit holder who is a nonresident alien individual or which is
a foreign corporation (collectively "Foreign Taxpayer") will be subject to tax
on the gross income produced by the Royalty at a rate equal to 30% (or lower
treaty rate, if applicable). This tax will be withheld by the Trustees and
remitted directly to the United States Treasury. A Foreign Taxpayer may elect to
treat the income from the Royalty as effectively connected with the conduct of a
United States trade or business under Section 871 or Section 882 of the Internal
Revenue Code of 1986, as amended (the "Code") (or pursuant to any similar
provisions of applicable treaties). Upon making such election such Unit holder
is entitled to claim all deductions with respect to such income, but he must
file a United States income tax return to claim such deductions. This election
once made is irrevocable (unless an applicable treaty allows the election to be
made annually). However, for tax years beginning after December 31, 1987, such
effectively connected income is subjected to withholding equal to the highest
applicable percentage (tax rate) -- 39.6% for individual foreign Unit holders
and 35% for corporate foreign Unit holders.
Section 897 of the Code and the Treasury Regulations thereunder treat the
publicly traded Trust as if it were a United States real property holding
corporation. Accordingly, Foreign Unit holders owning greater than 5 percent of
the outstanding Units (or 237,576 Units) are subject to United States income tax
on the
7
<PAGE>
gain on the disposition of their Units. Foreign Unit holders owning 5 percent or
less are not subject to United States income tax on the gain on the disposition
of their Units.
Federal income taxation of a Foreign Taxpayer is a highly complex matter
which may be affected by many other considerations. Therefore, each Foreign
Taxpayer should consult his own tax adviser as to the advisability of his
ownership of Units.
TAX-EXEMPT ORGANIZATIONS
Investments in publicly traded partnerships are treated the same as
investments in other partnerships for purposes of the rules governing unrelated
business taxable income. The Royalty and interest income of the Partnership
should not be unrelated business taxable income so long as, generally, a Unit
holder did not incur debt to acquire a Unit or otherwise incur or maintain a
debt that would not have been incurred or maintained if such Unit had not been
acquired. Legislative proposals have been made from time to time which, if
adopted, would result in the treatment of Royalty income as unrelated business
income. Tax-exempt Unit holders should consult their own tax advisors with
respect to the treatment of Royalty income.
STATE LAW CONSIDERATIONS
The Trust and the Partnership have been structured so as to cause the Units
to be treated for certain state law purposes essentially the same as other
securities, that is, as interests in intangible personal property rather than as
interests in real property. However, in the absence of controlling legal
precedent, there is a possibility that under certain circumstances a Unit holder
could be treated as owning an interest in real property under the laws of
Louisiana. In that event, the tax, probate, devolution of title and
administration laws of Louisiana or other states applicable to real property may
apply to the Units, even if held by a person who is not a resident thereof.
Application of such laws could make the inheritance and related matters with
respect to the Units substantially more onerous than had the Units been treated
as interests in intangible personal property. Unit holders should consult their
legal and tax advisers regarding the applicability of these considerations to
their individual circumstances.
TERMINATION OF THE TRUST
The terms of the TEL Offshore Trust Agreement provide that the Trust will
terminate upon the first to occur of the following events: (1) total future net
revenues attributable to the Partnership's interest in the Royalty, as
determined by independent petroleum engineers, as of the end of any year, are
less than $2 million or (2) a decision to terminate the Trust by the affirmative
vote of Unit holders representing a majority of the Units. Total future net
revenues attributable to the Partnership's interest in the Royalty were
estimated at $24.3 million as of October 31, 1997, based on the reserve study of
DeGolyer and MacNaughton, independent petroleum engineers, discussed herein.
Based on the DeGolyer and MacNaughton reserve study, as of October 31, 1997, it
is estimated that approximately 80% of future net revenues from the Royalty
Properties are expected to be received by the Trust during the next 3 years.
Because the Trust will terminate in the event estimated future net revenues fall
below $2.0 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 the limitations
described in the DeGolyer and MacNaughton reserve study. The reserve study is
limited to reserves classified as proved; therefore, future capital expenditures
for recovery of reserves not classified as proved by DeGolyer and MacNaughton
are not included in the calculation of estimated future net revenues. In
addition, 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
8
<PAGE>
entirety by reference to the Trust Agreement itself, which is an exhibit to this
Form 10-K and is available upon request from the Corporate Trustee.
In addition, in the event of a dissolution of the Partnership (which could
occur under the circumstances described above under "Description of the
Trust") and a subsequent winding up and termination thereof, the assets of the
Partnership (i.e., the Royalty) could either (i) be distributed in kind ratably
to the Trust and the Managing General Partner or (ii) be sold and the proceeds
thereof distributed ratably to the Trust and the Managing General Partner. In
the event of a sale of the Royalty and a distribution of the cash proceeds
thereof to the Trust and the Managing General Partner, the Trustee would make a
final distribution to Unit holders of the Trust's portion of such cash proceeds
plus any other cash held by the Trust after payment of or provision for all
liabilities of the Trust, and the Trust would be terminated.
ROYALTY INCOME, DISTRIBUTABLE INCOME AND TOTAL ASSETS
Reference is made to Items 6, 7 and 8 of this Form 10-K for financial
information relating to the Trust.
DESCRIPTION OF ROYALTY PROPERTIES
PRODUCING ACREAGE AND WELLS
The Partnership's interest consists of an overriding royalty interest,
equivalent to a 25% net profits interest, in the Royalty Properties as follows:
<TABLE>
<CAPTION>
GROSS WELLS DRILLED
AS OF OCTOBER 31, 1997
WORKING ---------------------------
INTEREST
OWNER'S WELLS SUCCESS-
ACQUISITION OWNERSHIP DRILLED(1) FUL(2)(3)
DATE INTEREST GROSS ------------- ----------
PROPERTY (MO.-YR.) (%) ACRES EXPL. DEV. OIL GAS
- ---------------------------------------------------- ----------- --------- --------- ----- ---- --- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
East Cameron 354.................................... 12-72 50.00 5,000 2 4 0 5
West Cameron 643.................................... 12-72 50.00 5,000 2 17 0 13
Eugene Island 339................................... 12-72 50.00 5,000 2 34 31 0
Eugene Island 342................................... 12-72 1.00 5,000 2 20 0 16
Eugene Island 343................................... 12-72 1.00 5,000 4 16 0 17
Eugene Island 348................................... 12-72 50.00 5,000 4 5 0 7
West Cameron 642.................................... 1-73 25.00 5,000 3 7 0 7
East Cameron 370(4)................................. 1-73 25.00 5,000 3 1 0 4
East Cameron 371.................................... 1-73 25.00 5,000 3 1 0 1
Vermilion 246....................................... 1-73 36.30 5,000 3 2 0 3
West Cameron 41 E/2(5).............................. 3-74 .30 2,500 -- 0 0 0
Ship Shoal 183 N/2.................................. 12-73 66.70 2,500 -- 27 26 0
Ship Shoal 183 NW/4 of S/2.......................... 4-77 50.00 625 -- 1 1 0
Ship Shoal 183 NE/4 of SW/4
of S/2, SE/4...................................... 12-82 50.00 1,875 1 -- 1 0
Eugene Island 208................................... 8-73 100.00 1,250 -- 3 0 3
Eugene Island 367................................... 3-74 1.60 5,000 2 9 0 9
South Marsh Island 252.............................. 3-74 .22 4,997 2 -- 0 1
South Timbalier 36.................................. 3-74 .30 5,000 2 20 9 11
South Timbalier 37.................................. 3-74 .30 5,000 3 28 18 1
--------- ----- ---- --- ---
78,747 38 178 76 98
========= ===== ==== === ===
</TABLE>
- ------------
(1) As of October 31, 1997, there were no wells in the process of drilling.
See "Operations" under Item 7 of this report for a discussion of
drilling activity during 1997.
(2) As of October 31, 1997, there were 79 producing completions.
(3) Multiple completions are counted as one well. South Timbalier 36 has 10
multiple completion wells and South Timbalier 37 has 6 multiple completion
wells.
(4) This lease expired in 1996.
(5) This lease was abandoned and expired in 1991.
9
<PAGE>
RESERVES
A study of the proved oil and gas reserves attributable to the Partnership,
in which the Trust has a 99.99% interest, has been made by DeGolyer and
MacNaughton, independent petroleum engineering consultants, as of October 31,
1997. The following letter summarizes such reserve study. Such study reflects
estimated production, reserve quantities and future net revenue based upon
estimates of the future timing of actual production without regard to when
received by the Trust, which differs from the manner in which the Trust
recognizes its royalty income. See Notes 3 and 9 in the Notes to Financial
Statements under Item 8 of this Form 10-K.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data in the DeGolyer and MacNaughton letter represent
estimates only and should not be construed as being exact. The discounted
present values shown by the DeGolyer and MacNaughton letter should not be
construed as the current market value of the estimated gas and oil reserves
attributable to the Royalty Properties or the costs that would be incurred to
obtain equivalent reserves, since a market value determination would include
many additional factors. In accordance with applicable regulations of the
Securities and Exchange Commission (the "SEC"), estimated future net revenues
were based, generally, on current prices and costs, whereas actual future prices
and costs may be materially greater or less. In addition, because the reserve
study is limited to proved reserves, future capital expenditures for recovery of
reserves not classified as proved by DeGolyer and MacNaughton are not included
in the calculation of estimated future net revenues. Reserve assessment is a
subjective process of estimating the recovery from underground accumulations of
gas and oil that cannot be measured in an exact way, and estimates of other
persons might differ materially from those of DeGolyer and MacNaughton.
Accordingly, reserve estimates are often different from the quantities of
hydrocarbons that are ultimately recovered.
The Partnership's share of gas sales are recorded by the Working Interest
Owners on the cash method of accounting. Under this method, revenues are
recorded based on actual gas volumes sold which could be more or less than the
volumes the Working Interest Owners are entitled to based on their ownership
interests. The Partnership's Royalty income for a period reflects the actual gas
sold during the period. Chevron has advised the Trust that, as of October 31,
1997, approximately 109,900 Mcf had been overtaken by Chevron from the Eugene
Island 339 property. The Partnership's share of revenues related to the
overtaken gas was included in the Partnership's Royalty income in the periods
during which the gas was sold. Accordingly, the reserves and future Royalty
income attributable to the Partnership, as discussed in the DeGolyer and
MacNaughton letter and shown in Note 9 in the Notes to Financial Statements
under Item 8 of this Form 10-K, have been reduced by the Partnership's share of
such imbalance. The standardized measure of discounted future Royalty income
attributable to the Partnership was reduced by approximately $73,600 in 1997
related to such imbalance. Chevron has advised the Trust that sufficient gas
reserves exist on Eugene Island 339 for underproduced parties to recoup their
share of the gas imbalance on that property.
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 $166,100, $5,000 and $150,000 was recovered from the Trust by the
Working Interest Owner during 1997, 1996 and 1995, respectively, 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.
10
<PAGE>
LETTER REPORT
AS OF
OCTOBER 31, 1997
ON
RESERVES AND REVENUE
OF
CERTAIN PROPERTIES
OWNED BY THE
TEL OFFSHORE TRUST PARTNERSHIP
SEC CASE
11
<PAGE>
DEGOLYER AND MACNAUGHTON
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
January 30, 1998
Chevron USA Inc.
Chevron Place
935 Gravier Street
New Orleans, Louisiana 70012
Gentlemen:
Pursuant to your request, we have prepared estimates, as of October 31,
1997, of the extent and value of the proved crude oil, condensate, and natural
gas reserves of a net profits interest owned by TEL Offshore Trust Partnership
(the Trust Partnership). This net profits interest (the Trust Partnership
Interest) is in certain offshore leases owned by Chevron USA Inc. (Chevron), as
successor in title to Tenneco Oil Company (Tenneco), by Pennzoil Petroleum
Company (Pennzoil), as successor in title to Chevron, and by Texaco Exploration
and Production, Inc. (Texaco), as successor in title to Chevron. The interest
appraised consists of a 25-percent net profits interest in 17 leases (the
Subject Properties), which are located in the Gulf of Mexico offshore from
Louisiana. Before acquisition by Chevron, the Subject Properties had been
transferred to Tenneco upon the dissolution of Tenneco Exploration Ltd.
(Exploration I), a limited partnership formerly comprised of Tenneco and Tenneco
West Inc. Exploration I conveyed the net profits interest to the Trust
Partnership, which is 99.99-percent owned by TEL Offshore Trust, by the
Conveyance of Overriding Royalty Interests effective January 1, 1983. The
Subject Properties were acquired by Chevron on November 18, 1988. Certain of the
Subject Properties were subsequently acquired by Pennzoil effective July 1,
1992, and certain others were acquired by Texaco effective December 1, 1994. One
of the Pennzoil Subject Properties was subsequently acquired by SONAT
Exploration Company (SONAT) and certain other Pennzoil Subject Properties were
acquired by Amoco Production Company (Amoco), both effective October 1, 1995.
During this investigation, we consulted freely with the officers and
employees of Chevron and were given access to such accounts, records, geological
and engineering reports, and other data as were desired for examination. In the
preparation of this report we have relied, without independent verification,
upon information furnished by Chevron with respect to property interests owned
by the Trust Partnership, production from such properties, current costs of
operation and development, current prices for production, agreements relating to
current and future operations and sale of production, and various other
information and data that were accepted as represented. It was not considered
necessary to make a field examination of the physical condition and operation of
the Subject Properties.
Our reserves estimates are based on a detailed study of the Subject
Properties and were prepared by the use of standard geological and engineering
methods generally accepted by the petroleum industry. The method or combination
of methods used in the analysis of each reservoir was tempered by experience
with similar reservoirs, consideration of the stage of development of the
reservoir, and the quality and completeness of basic data.
Reserves estimated herein are expressed as gross and net reserves. Gross
reserves are defined as the total estimated petroleum to be produced from the
Subject Properties after October 31, 1997. Combined net reserves are defined as
those reserves remaining after deducting royalties from gross reserves. Net
reserves are defined as that portion of the combined net reserves attributable
to the interests owned by the Trust Partnership Interest after deducting
interests owned by others. Gas volumes are expressed as sales gas reserves at a
temperature of 60 degrees Fahrenheit and at a legal pressure bases of 14.73
pounds per square inch absolute. Sales gas is defined as the total gas to be
produced from the reservoirs, measured at the point
12
<PAGE>
DEGOLYER AND MACNAUGHTON
of delivery, after reduction for fuel usage, flare, and shrinkage resulting from
field separations and precessing. Condensate reserves estimated herein are those
to be obtained by normal separator recovery.
Petroleum reserves included in this report are classified as proved and are
judged to be economically producible in future years from known reservoirs under
existing economic and operating conditions and assuming continuation of current
regulatory practices using conventional production methods and equipment. In the
analyses of production-decline curves, reserves were estimated only to the limit
of economic rates of production under existing economic and operating conditions
using prices and costs as of the date the estimate is made, including
consideration of changes in existing prices provided only by contractual
arrangements but not including escalations based upon future conditions. The
petroleum reserves are classified as follows:
PROVED--Reserves that have been proved to a high degree of certainty by
analysis of the producing history of a reservoir and/or by volumetric
analysis of adequate geological and engineering data. Commercial
productivity has been established by actual production, successful
testing, or in certain cases by favorable core analyses and
electrical-log interpretation when the producing characteristics of the
formation are known from nearby fields. Volumetrically, the structure,
areal extent, volume, and characteristics of the reservoir are well
defined by a reasonable interpretation of adequate subsurface well
control and by known continuity of hydrocarbon-saturated material above
known fluid contacts, if any, or above the lowest known structural
occurrence of hydrocarbons.
DEVELOPED--Reserves that are recoverable from existing wells with
current operating methods and expenses.
Developed reserves include both producing and nonproducing reserves.
Estimates of producing reserves assume recovery by existing wells
producing from present completion intervals with normal operating
methods and expenses. Developed nonproducing reserves are in
reservoirs behind the casing or at minor depths below the producing
zone and are considered proved by production from other wells in the
field, by successful drill-stem tests, or by core analyses from the
particular zones. Nonproducing reserves require only moderate expense
to be brought into production.
UNDEVELOPED--Reserves that are recoverable from additional wells yet
to be drilled.
Undeveloped reserves are those considered proved for production by
reasonable geological interpretation of adequate subsurface control
in reservoirs that are producing or proved by other wells but are not
recoverable from existing wells. This classification of reserves
requires drilling of additional wells, major deepening of existing
wells, or installation of enhanced recovery or other facilities.
Reserves recoverable by enhanced recovery methods, such as injection of
external fluids to provide energy not inherent in the reservoirs, may be
classified as proved developed or proved undeveloped reserves depending upon the
extent to which such enhanced recovery methods are in operation. These reserves
are considered to be proved only in cases where a successful fluid-injection
program is in operation, a pilot program indicates successful fluid injection,
or information is available concerning the successful application of such
methods in the same reservoir and it is reasonably certain that the program will
be implemented.
The properties evaluated consist of 17 leases located offshore from
Louisiana. These 17 leases include 13 productive properties (including 2 leases
covering separate portions of the south half of Ship Shoal Block 183) and 4
leases to which no reserves have been assigned. Pennzoil owns an interest in one
of the productive properties and in one of the leases to which no reserves have
been assigned. Texaco owns an
13
<PAGE>
DEGOLYER AND MACNAUGHTON
interest in four of the productive properties. SONAT and Amoco own an interest
in one property each, but only the SONAT property is productive.
The reserves volumes and revenue values shown in this report were estimated
from projections of reserves and revenue attributable to the combined interests,
which consist of the Trust Partnership Interest and the interests retained in
the Subject Properties by Chevron, Pennzoil, Texaco, SONAT, or Amoco. Net
reserves attributable to the Trust Partnership Interests were estimated by
allocating to the Trust Partnership a portion of the estimated combined net
reserves of the Subject Properties based on future revenue. The formula used to
estimate the net reserves attributable to the Trust Partnership Interest is as
follows:
<TABLE>
<CAPTION>
<C> <C> <S>
Trust Partnership Interest
future net revenue
Trust Partnership Interest net reserves = ----------------------------- x Combined net reserves
Combined future gross revenue
</TABLE>
This formula was applied separately to the Pennzoil, Texaco, SONAT, and
Amoco groups of properties and then to the Chevron (remaining properties) group;
the results were then added together to obtain the total reserves and revenue
for the Trust Partnership Interest. Because the net reserves volumes
attributable to the Trust Partnership Interest are estimated using an allocation
of reserves based on estimates of future revenue, a change in prices or costs
will result in changes in the estimated net reserves. Therefore, the estimated
net reserves attributable to the Trust Partnership Interest will vary if
different future price and cost assumptions are used. Trust Partnership Interest
net revenue and net reserves estimates included in this report have been
estimated from reserves and revenue attributable to the combined interests using
procedures and calculation methods as specified by Chevron and represented by
Chevron to be in accordance with the Conveyance of Overriding Royalty Interests.
Units have been formed for several common reservoirs that underlie the
Subject Properties and adjacent leases. In those cases, the estimated gross
reserves of the entire reservoir are shown and the resulting combined Trust
Partnership and Chevron, Pennzoil, Texaco, SONAT, or Amoco interests in the
reservoir unit are used to calculate combined interests net reserves.
In the Eugene Island Block 339 field, gas from certain properties has been
produced and sold, but one owner has not taken its full share of the produced
gas. In this case, there is in effect a gas-balancing agreement whereby gas not
taken is credited to the account of the owner not currently selling its share of
the produced gas. That gas is to be recovered by increasing this party's share
of the monthly gas production in the future. The net reserves and revenue shown
herein are the future reserves and revenue attributable to the Trust Partnership
Interest, including adjustments for the existing balancing agreement in the
Eugene Island Block 339 field.
Data available from wells drilled on the appraised properties through
October 1997 were used in estimating gross ultimate recovery. Gross production
estimated through October 31, 1997, was deducted from the gross ultimate
recovery to arrive at estimates of gross reserves. In most fields, this required
that the production rates be estimated for 4 months, since production data for
certain properties were available only through June 1996.
14
<PAGE>
DEGOLYER AND MACNAUGHTON
Net proved reserves attributable to the Trust Partnership Interest, as of
October 31, 1997, are estimated as follows:
OIL AND NATURAL
CONDENSATE GAS
(BBL) (MCF)
---------- ---------
Proved Developed and Undeveloped
Reserves
Reserves as of October 31, 1996....... 918,021 4,893,525
Revisions of Previous Estimates....... 146,239 63,599
Improved Recovery..................... 0 0
Purchases of Minerals in Place........ 0 0
Extensions, Discoveries, and Other
Additions........................... 11,887 221,520
Production............................ (374,154) (1,782,704)
Sales of Minerals in Place............ 0 0
Reserves as of October 31, 1997....... 701,993 3,395,940
Proved Developed Reserves
Reserves as of October 31, 1996....... 917,883 4,885,185
Reserves as of October 31, 1997....... 695,022 3,169,790
Revenue values in this report are expressed in terms of estimated combined
future net revenue, future net revenue attributable to the Trust Partnership
Interest, and present worth of these future net revenues. Future gross revenue
is that revenue which will accrue from the production and sale of the estimated
combined net reserves. Combined future net revenue values were calculated by
deducting operating expenses and capital costs from the future gross revenue of
the combined interest. These monthly values for the aggregate of the combined
interest in the Subject Properties were reduced by a trust overhead charge
furnished by Chevron. Capital and abandonment costs for longer-life properties
were accrued at the end of each quarter in amounts specified by Chevron
beginning in January 1998. The future accrual or escrow amounts for each of the
five groups of properties were deducted from the combined future net revenue at
the end of each quarter, as specified by Chevron. Interest on the balance of the
accrued capital and abandonment costs at the rate of 4.75 percent per year as
specified by Chevron was credited monthly as a reduction in operating costs. The
adjusted revenue resulting from subtracting the overhead charge and accrued
capital and abandonment costs was multiplied by a factor of 25 percent to arrive
at the future net revenue attributable to the Trust Partnership Interest. The
above calculations were made monthly for each of the five groups of the
properties (Chevron, Pennzoil, Texaco, SONAT, and Amoco). Interest was charged
monthly on the net profits deficit balances (costs not recovered currently) at
the rate of 4.75 percent per year as specified by Chevron. Present worth is
defined as future net revenue discounted at a specified arbitrary discount rate
compounded monthly over the expected period of realization; in this report,
present worth values using a discount rate of 10 percent are reported. Future
income tax expenses were not taken into account in estimating future net revenue
and present worth. No deductions were made in the foregoing reserves for any
outstanding production payments.
Revenue values in this report were estimated using the initial prices and
costs provided by Chevron. Future prices were estimated using guidelines
established by the Securities and Exchange Commission (SEC) and the Financial
Accounting Standards Board (FASB). These guidelines require the use of prices
for oil and condensate in effect on October 31, 1997. The initial and future
prices and producing rates used in this report have been reviewed by Chevron and
it has represented that the gas prices and rates used herein are those that the
Trust Partnership could reasonably expect to receive on October 31, 1997. The
assumptions used for estimating future prices and costs are as follows:
OIL AND CONDENSATE PRICES
Oil and condensate prices applicable in October 1997 were used as
initial prices with no increases based on inflation. The initial oil and
condensate prices were furnished by Chevron.
15
<PAGE>
DEGOLYER AND MACNAUGHTON
NATURAL GAS PRICES
Initial gas prices furnished by Chevron were prices in effect on October
31, 1997, and were represented to be in accordance with existing gas
contracts. Chevron further represents that these contracts provide for
periodic price redeterminations, but do not provide for any fixed or
determinable escalations. Therefore, the initial prices were used for
the remaining life of the properties.
OPERATING AND CAPITAL COSTS
Current estimates of operating costs were used for the life of the
properties with no increases in the future based on inflation. Future
capital expenditures were estimated using 1997 values and were not
adjusted for inflation. Abandonment costs have been estimated as capital
costs for all properties, including the four leases which are considered
depleted and to which no reserves have been assigned.
A summary of estimated revenue and costs attributable to the combined
interest in proved reserves of the Subject Properties and the future net revenue
and present worth attributable to the Trust Partnership Interest, as of October
31, 1997, is as follows:
<TABLE>
<CAPTION>
CHEVRON PENNZOIL TEXACO SONAT AMOCO
PROPERTIES PROPERTIES PROPERTIES PROPERTIES PROPERTIES TOTAL
----------- ----------- ----------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
COMBINED INTEREST
Future Gross Revenue ($)......... 82,417,001 1,830,766 16,875,101 1,569,530 0 102,692,398
Operating Costs ($).............. (9,426,489) (299,736) (2,021,719) (299,212) 0 (12,047,156)
Capital Costs ($)(1)............. (5,855,639) (525,000) (4,370,268) (278,410) 0 (11,029,317)
Future Net Revenue ($)........... 67,134,873 1,006,030 10,483,114 991,908 0 79,615,925
Cost Escrow as of 10-31-97 ($)... 10,603,752 220,920 7,667,612 275,220 4,972 18,772,476
Interest Credit on Accrued
Balance ($).................... 1,735,049 170,849 660,665 39,093 119 2,605,775
Interest on Deficit ($).......... (73) (1,429) 0 0 0 (1,502)
Overhead ($)..................... (2,982,830) (84,639) (717,700) (65,541) 0 (3,850,710)
Revenue Subject to Net Profits
Interest ($)................... 76,490,771 1,311,731 18,093,691 1,240,680 5,091 97,141,964
TRUST PARTNERSHIP INTEREST
Future Net Revenue ($)(2)........ 19,122,644 327,908 4,523,386 310,160 1,268 24,285,366
Present Worth at 10 Percent
($)(2)......................... 15,986,060 249,502 3,946,446 276,651 1,215 20,459,874
</TABLE>
1 Includes abandonment costs.
2 Future income tax expenses were not taken into account in the preparation of
these estimates.
In our opinion, the information relating to estimated proved reserves,
estimated future net revenue from proved reserves, and present worth of
estimated future net revenue from proved reserves of oil, condensate, and gas
contained in this report has been prepared in accordance with Paragraphs 10-13,
15 and 30(a)-(b) of Statement of Financial Accounting Standards No. 69 (November
1982) of the FASB and Rules 4-10(a) (1)-(13) of Regulation S-X and Rule 302(b)
of Regulation S-K of the SEC; provided, however, future income tax expenses have
not been taken into account in estimating the future net revenue and present
worth values set forth herein.
16
<PAGE>
DEGOLYER AND MACNAUGHTON
To the extent the above-enumerated rules, regulations, and statements
require determinations of an accounting or legal nature or information beyond
the scope of this report, we are necessarily unable to express an opinion as to
whether the above-described information is in accordance therewith or sufficient
therefor.
In our opinion, we have made the investigations necessary to enable us to
estimate the petroleum reserves reported herein. Estimates of oil, condensate,
and gas reserves and future net revenue should be regarded only as estimates
that may change as further production history and additional information become
available. Not only are such reserves and revenue estimates based on that
information which is currently available, but such estimates are also subject to
the uncertainties inherent in the application of judgmental factors in
interpreting such information.
Submitted,
DeGOLYER and MacNAUGHTON
JAMES W. HAIL, JR., P.E.
James W. Hail, Jr., P.E.
Senior Vice President
DeGolyer and MacNaughton
17
<PAGE>
While estimates of reserves attributable to the Royalty are shown in order
to comply with requirements of the SEC, there is no precise method of allocating
estimates of physical quantities of reserves to the Partnership and the Trust,
since the Royalty is not a working interest and the Partnership does not own and
is not entitled to receive any specific volume of reserves from the Royalty.
Reserve quantities in the DeGolyer and MacNaughton reserve study have been
allocated based on a revenue formula described in the foregoing letter. The
quantities of reserves indicated by such formula will be affected by future
changes in various economic factors utilized in estimating future gross and net
revenues from the Royalty Properties. Therefore, the estimates of reserves set
forth in the DeGolyer and MacNaughton letter are to a large extent hypothetical
and differ in significant respects from estimates of reserves attributable to a
working interest. For a further discussion of reserves, reference is made to
Note 9 in the Notes to Financial Statements under Item 8 of this Form 10-K.
The future net revenues contained in the DeGolyer and MacNaughton letter
have not been reduced for future costs and expenses of the Trust, which are
expected to approximate $455,300 annually. The costs and expenses of the Trust
may increase in future years, depending on increases in accounting, engineering,
legal and other professional fees, as well as other factors.
In addition, because the DeGolyer and MacNaughton reserve study is limited
to proved reserves, future capital expenditures for recovery of reserves not
classified as proved by DeGolyer and MacNaughton are not included in the
calculation of future net revenues. Such capital expenditures could have a
significant effect on the actual future net revenues attributable to the
Partnership's interest in the Royalty.
The Trust Agreement provides that the Trust will terminate in the event
total future net revenues attributable to the Partnership's interest in the
Royalty as determined by independent petroleum engineers, as of the end of any
year, are less than $2.0 million. See "Business -- Termination of the Trust".
The Working Interest Owners have advised the Trust that there have been no
events subsequent to October 31, 1997 that have caused a significant change in
the estimated proved reserves referred to in the DeGolyer and MacNaughton
letter.
OPERATIONS AND PRODUCTION
Reference is made to the Section entitled "Operations" under Item 7 of
this Form 10-K for information concerning operations and production.
MARKETING
The amount of cash distributions by the Trust is dependent on, among other
things, the sales prices for oil and gas produced from the Royalty Properties
and the quantities of oil and gas sold. The oil and gas industry in the United
States during the past decade has been affected generally by a surplus in
deliverability in comparison to demand. Demand for oil and gas has generally
trailed deliverability during this period due to a number of factors including
the implementation of energy conservation programs, a shift in economic activity
away from energy intensive industries and competition from alternative fuel
sources.
Spot domestic natural gas prices were seasonally higher in early 1997 and
late 1997, but are declining in early 1998. Crude oil prices generally decreased
in 1997 and early 1998.
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 gas,
weather, industrial growth, conservation measures, competition and other
variables.
GAS MARKETING
During 1997, gas sales by the Working Interest Owners under a contract with
Texaco Natural Gas, Inc. and NGC Corporation accounted for 61% and 33%,
respectively, of total gas revenues from the Royalty Properties. Such contracts
provide for gas to be purchased by Texaco Natural Gas, Inc. and NGC Corporation
at a calculated price based on the monthly Inside FERC Tennessee-Louisiana Zone
1 index.
Effective August 31, 1996, Chevron's Natural Gas Business Unit and Warren
Petroleum Company merged with NGC Corporation. As a result of this merger, since
September 1996 all of Chevron's natural gas and natural gas liquids relative to
the Trust's Royalty Properties have been committed and sold to NGC
18
<PAGE>
Corporation at spot market index prices. See "Certain Relationships and Related
Transactions" under Item 13 of this Form 10-K.
It should be noted that the Conveyance provides that amounts received by
the producer pursuant to "take-or-pay" provisions are not included within the
Royalty payable to the Trust unless and until gas is actually delivered pursuant
to the "make-up" provisions, if any, of the applicable contract. Accordingly,
amounts received by the Working Interest Owners as "take-or-pay" payments are
not included in the calculation of the Royalty payable, and the income received
by the Trust is restricted to amounts paid for gas actually delivered.
Due to the seasonal nature of demand for natural gas and its effects on
sales prices and production volumes, the amount of gas sold with respect to the
Royalty Properties may vary. Generally, production volumes and prices are higher
during the first and fourth quarters of each calendar year. Because of the time
lag between the date on which the Working Interest Owners receive payment for
production from the Royalty Properties and the date on which distributions are
made to Unit holders, the seasonality that generally affects production volumes
and prices of is generally reflected in distributions to the Trust in later
periods.
The following paragraphs discuss the marketing of gas from the principal
Royalty Properties.
WEST CAMERON 643. West Cameron 643 contributed approximately 60% of the
revenues from gas sales from the Royalty Properties in 1997. The average price
received for natural gas from all of the Working Interest Owner's purchasers on
West Cameron 643 during 1997 was $2.72 per Mcf and the price received for
February 1998 was $2.10 per Mcf. The gas from West Cameron 643 is currently
committed under the contract with Texaco Natural Gas, Inc.
SHIP SHOAL 182/183. Ship Shoal 182/183 contributed approximately 28% of the
revenues from gas sales from the Royalty Properties in 1997. The average price
received for natural gas from all of the Working Interest Owner's purchasers on
Ship Shoal 182/183 during 1997 was $2.64 per Mcf and the price received for
February 1998 was $2.14 per Mcf. The gas from Ship Shoal 182/183 is committed to
NGC Corporation, as described above.
EUGENE ISLAND 339. Eugene Island 339 contributed approximately 5% of the
revenues from gas sales from the Royalty Properties in 1997. The average price
received for natural gas from all of the Working Interest Owner's purchasers on
Eugene Island 339 during 1997 was $2.80 per Mcf and the price received for
February 1998 was $2.26 per Mcf. The gas from Eugene Island 339 is committed to
NGC Corporation, as described above.
OIL MARKETING
Crude oil purchases by Texaco, Inc. and by the Supply and Distribution
Department of Chevron accounted for approximately 68% and 32%, respectively, of
total crude oil revenues from the Royalty Properties during 1997.
Texaco, Inc. purchases crude oil at prices based on its own published
pricing bulletin with an adjustment for gravity and transportation charges.
Average monthly prices for fiscal 1997 ranged from $18.06 per bbl to $24.37 per
bbl. The average crude oil price under this arrangement for February 1998 was
approximately $15.33 per bbl.
The Supply and Distribution Department of Chevron purchases crude oil at
prices based on its own published pricing bulletins with an adjustment for
gravity and transportation charges. Average monthly prices for fiscal 1997
ranged from $17.28 per bbl to $23.91 per bbl. The average price of crude oil
sold under this arrangement for February 1998 was approximately $13.95 per bbl.
19
<PAGE>
COMPETITION AND REGULATION
COMPETITION
The Working Interest Owners experience competition from other oil and gas
companies in all phases of its operations. Numerous companies participate in the
exploration for and production of oil and gas. The Working Interest Owners have
advised the Trust that they believe that their competitive positions are
affected by price and contract terms. Business is affected not only by such
competition, but also by general economic developments, governmental regulations
and other factors.
REGULATION -- GENERAL
The production of oil and gas by the Working Interest Owners is affected by
many state and federal regulations with respect to allowable rates of
production, drilling permits, well spacing, marketing, environmental matters and
pricing. Future regulations could change allowable rates of production or the
manner in which oil and gas operations may be lawfully conducted. Sales of
natural gas in interstate commerce for resale and the transportation of natural
gas in interstate commerce are subject to regulation by the Federal Energy
Regulatory Commission ("FERC") under the Natural Gas Act of 1938, as amended
(the "Natural Gas Act").
The operations of the Working Interest Owners under federal oil and gas
leases offshore the United States are subject to regulations of the United
States Department of Interior which currently impose absolute liability upon
lessees for the cost of cleanup of pollution resulting from their operations.
In the past, the federal government regulated the prices at which natural
gas could be sold. However, in July 1989, the Natural Gas Decontrol Act of 1989
was enacted, which provided for complete price decontrol of first sales of gas
as of January 1993 through repealing Title I of the Natural Gas Policy Act of
1978. Prior to January 1993, this Act provided for: (1) immediate decontrol of
gas to which no first sales contract applied on date of enactment; (2) decontrol
of gas under existing gas contracts as the contracts expire or are terminated;
(3) decontrol in May 1991 of gas covered by sales contracts on the date of
enactment and produced from wells spudded after the date of enactment and (4)
decontrol of gas under contracts renegotiated after March 23, 1989 to provide
that maximum lawful prices will not apply.
Commencing in late 1985 and early 1986, the FERC issued a series of rules
and orders (Order No. 436, Order No. 500, and related orders) that made sweeping
changes in its regulations governing the transportation and marketing of natural
gas supplies. Among other things, the new regulations (i) require interstate
pipelines that elect to transport gas for others under self-implementing
authority to provide transportation services to all shippers on a
non-discriminatory basis; (ii) permit each existing firm sales customer of such
pipelines to modify over at least a five-year period its existing purchase
obligations; (iii) establish a complicated procedure to permit pipelines that
transport gas under the regulations to credit the volumes transported on a
volumetric basis against take-or-pay obligations under contracts in existence on
June 23, 1987; and (iv) establish guidelines that permit pipelines to recover
from customers all or a portion of payments made to producers in settlement of
take-or-pay contract disputes. On August 24, 1990, the D.C. Circuit upheld most
aspects of the final rule in the Order No. 500 series. Only issues regarding
pregranted abandonment of converted transportation services and double-crediting
were remanded by the Court to the FERC for further action. The pregranted
abandonment issue is addressed in Order No. 636. With respect to the double
crediting issue, on April 4, 1991, the FERC issued Order 500-K in which it ruled
that its take-or-pay crediting regulations did not result in producers providing
double take-or-pay credits in certain circumstances.
On April 8, 1992, the FERC issued Order No. 636, which implemented a major
restructuring of interstate pipeline operations in order to enhance the
competitive structure of the pipeline industry and maximize the benefits of a
competitive wellhead market resulting from wellhead price decontrols. Order No.
636 requires, among other things, that all interstate pipelines eliminate their
bundled city gate sales services by unbundling their sales services from their
transportation services. Unbundled sales customers have been given the right to
reduce their firm sales entitlements in whole or in part, thereby enabling such
customers to negotiate with other parties for long-term supplies. Order No. 636
also requires that open access pipelines provide transportation services
comparable in quality for all gas supplies, whether purchased from the pipeline
or elsewhere. The FERC would require that operational terms and conditions
imposed on a pipelines transportation service result in nondiscriminatory
treatment for pipeline sales gas
20
<PAGE>
and third party sales gas. In this way, pipelines, producers, marketers and all
other merchants of gas would be able to compete on an equal footing. The stated
purpose of Order No. 636 is to create a national gas market where a buyer can
reach many sellers by meaningful access to the pipeline transportation grid. On
August 3, 1992, the FERC issued Order No. 636-A, which largely reaffirmed Order
No. 636 and denied stay of the implementation of the new rule pending judicial
review. On November 27, 1992, the FERC issued Order No. 636-B, which uniformly
upheld the regulations adopted in Order Nos. 636 and 636-A. As a result of these
orders, individual so-called "restructuring" proceedings were established for
each interstate pipeline to develop particularized features and procedures for
each pipeline's system to implement Order No. 636. On July 16, 1996, the D.C.
Circuit issued its opinion on review of Order No. 636. The opinion upheld most
elements of Order No. 636 including the unbundling of sales and transmission
services, curtailment of pipeline capacity, implementation of the capacity
release program and the mandatory imposition of straight-fixed-variable
("SFV") rate design for interstate pipelines. The D.C. Circuit did remand
certain aspects of Order No. 636 to the Commission for further explanation
including, INTER ALIA, the right-of-first-refusal mechanism, the eligibility of
customers to receive notice transportation service, and SFV mitigation measures.
On February 27, 1997, the FERC issued Order No. 636-C, its order on remand from
the D.C. Circuit. Order No. 636-C is currently pending on rehearing before the
FERC. Appeals of individual pipeline restructuring orders are still pending
before the D.C. Circuit.
Although the Working Interest Owners are unable to predict the consequences
of the new rules, the Working Interest Owners believe such rules could have a
significant effect on all segments of the natural gas industry. Although the new
rules do not directly regulate gas producers such as Working Interest Owners,
the FERC has stated that the rules are intended primarily to foster increased
competition in the natural gas industry and to allow more accurate price signals
to be transmitted from consumers to producers, such as the Working Interest
Owners.
On December 9, 1988, the FERC issued Order No. 509 which provides every
jurisdictional interstate natural gas pipeline that transports gas on or across
the OCS with a blanket certificate authorizing and requiring nondiscriminatory
transportation of natural gas on behalf of others, and requires every OCS
pipeline to file tariffs to implement that blanket certificate authorization.
The service performed under the blanket certificate includes both firm and
interruptible transportation service and OCS pipelines must, pursuant to the
blanket certificate, provide open and nondiscriminatory access for both owner
and nonowner shippers. Order No. 509 also provided that if an OCS pipeline
received a request for service, the pipeline would be required to allocate
capacity pro rata in order to provide the requested service. Order No. 509 will
facilitate the transportation and marketability of OCS gas. On August 14, 1992,
the D.C. Circuit remanded the final rule back to the FERC for further
consideration as to whether the FERC has authority to require a pipeline to file
to abandon service to a shipper prior to the termination of the underlying
contract and to charge a replacement shipper the generally applicable rate, not
the old shipper's rate. On October 4, 1993, the FERC issued Order No. 559 in
which the FERC (1) addressed the issues raised by the Court's August 14, 1992
order and (2) amended certain regulations and removed other regulations
promulgated in Order No. 509. Specifically, the Commission removed the
regulations concerning the capacity allocation program established in Order No.
509 and the regulation providing for abandonment authority. The capacity
allocation regulations promulgated in Order No. 509 have been subsumed by the
Order No. 636 capacity release program.
In September of 1991, the FERC issued a final rule in Order 537 in which it
amended its regulations for the transportation of natural gas pursuant to
Section 311 of the NGPA. Generally, the final rule requires that for interstate
pipeline transportation under Section 311, the "on behalf of" entity
(interstate pipeline or local distribution company) must either (1) have
physical custody of or transport the gas at some point during the transaction or
(2) hold title to the gas at some point during the transaction for a purpose
related to its status as an intrastate pipeline or an LDC. In addition, the
final rule authorizes Section 311 transportation services by interstate
pipelines for end users located in the service areas of non-transporting,
non-title holding intrastate pipelines and LDC's that certify that the
interstate pipeline's transportation is on their behalf. On September 21, 1992,
the FERC issued Order No. 537-A which largely upheld the regulations adopted in
Order No. 537. On January 14, 1993, the FERC issued Order No. 537-B which
clarified Order No. 537-A. On April 25, 1994, the United States Court of Appeals
for the D.C. Circuit upheld Order Nos. 537, 537-A and 537-B.
21
<PAGE>
On February 28, 1996, the FERC issued a Statement of Policy regarding the
application of its jurisdiction under the NGA and the Outer Continental Shelf
Lands Act over new natural gas facilities and services on the Outer Continental
Shelf ("OCS"). In its Policy Statement, the FERC concluded that it will retain
its existing primary function test to determine whether particular facilities on
the OCS constitute gathering facilities exempt from the FERC's NGA jurisdiction.
However, the FERC added a new factor to its primary function test for facilities
that are designed to collect gas produced in water depths of 200 meters or more.
Such facilities now will be presumed to qualify as gathering facilities up to
the point or points of potential connection with the interstate pipeline grid.
Downstream of that point, the facilities will be evaluated under the existing
primary function test. Existing interstate pipelines and gathering facilities
would retain their present status barring some change in circumstances. On June
14, 1996, the Commission dismissed all requests for rehearing of its February
28, 1996 order.
On July 17, 1996, the FERC issued Order No. 587 which revised the FERC's
regulations to require interstate natural gas pipelines to follow standardized
procedures issued by the Gas Industry Standards Board ("GISB") for certain
business practices, I.E., nominations, allocations, balancing, measurement,
invoicing, capacity release and electronic communication between the pipelines
and those with whom they do business. On January 30, 1997, in Order No. 587-B,
the FERC incorporated into its regulations a second set of GISB standards that
would, INTER ALIA, require interstate pipelines to conduct business transactions
and provide other information according to Internet protocols and to abide by
certain business practice standards dealing with nominations, flowing gas and
capacity release. On March 4, 1997, the FERC issued Order No. 587-C which
amended the FERC's regulations to adopt standards requiring interstate pipelines
to publish certain information on Internet web pages and to implement new
business practice standards covering nominations and flowing gas. The Commission
has denied requests for rehearing of Order Nos. 587, ET SEQ. The appeal of Order
No. 587 is pending before the D.C. Circuit. The intent of these standards is to
establish a more efficient and integrated pipeline grid which will reduce the
variations in pipeline business practices and allow buyers to obtain and
transport gas from all potential sources of supply more easily and efficiently.
The Trust cannot predict the full effect that continuing judicial,
legislative and regulatory involvement in various natural gas issues will have
on prices, markets or terms of sale of natural gas.
ENVIRONMENTAL REGULATIONS
GENERAL
The Working Interest Owners' oil and gas activities on the Royalty
Properties are subject to existing and evolving federal, state and local
environmental laws and regulations. The Working Interest Owners have advised the
Trust that they believe that their operations and facilities are in general
compliance with applicable health, safety, and environmental laws and
regulations that have taken effect at the federal, state and local levels. In
addition, events in recent years have heightened environmental concerns about
the oil and gas industry generally, and about offshore operations in particular.
The Working Interest Owners' operation of federal offshore oil and gas leases is
subject to extensive governmental regulation, including regulations that may, in
certain circumstances, impose absolute liability upon lessees for cost of
removal of pollution and for pollution damages resulting from their operations,
and require lessees to suspend or cease operations in the affected areas.
Under the Oil Pollution Act of 1990, as amended by the Coast Guard
Authorization Act of 1996, (collectively, "OPA"), parties responsible for
offshore facilities must establish and maintain evidence of oil-spill financial
responsibility ("OSFR") for costs attributable to potential oil spills. OPA
requires a minimum of $35 million in OSFR for offshore facilities located on the
OCS. This amount is subject to upward regulatory adjustment up to $150 million.
Responsible parties for more than one offshore facility are required to provide
OSFR only for their offshore facility requiring the highest OSFR. On March 25,
1997, the Mineral Management Service proposed regulations for establishing the
amount of OSFR to be required for particular facilities. Under the proposed
rule, the amount of OSFR will increase as the volume of a facility's worst-case
oil spill increases. Accordingly, for facilities with worst-case spills of less
than 35,000 barrels, only $35 million in OSFR will be required; for worst-case
spills of over 35,000 barrels, $70 million will be required; for worst-case
spills of over 70,000 barrels, $105 million will be required; and for worst-case
spills of over 105,000 barrels, $150 million will be required. In addition, all
OSFR below $150 million remains subject to upward regulatory adjustment if
warranted by the particular operational,
22
<PAGE>
environmental, human health or other risks involved with a facility. Although
the Working Interest Owners have advised the Trust that current environmental
regulation has had no material adverse effect on the Working Interest Owners'
present method of operations, the impact of the recently adopted and proposed
regulatory changes, and of future environmental regulatory developments such as
stricter environmental regulation and enforcement policies, cannot presently be
quantified.
The Working Interest Owners' operations are subject to regulation,
principally under the following federal statutes, along with their analogous
state statutes.
WATER
The Federal Water Pollution Control Act of 1972, as amended, and the Oil
Pollution Act of 1990 impose certain liabilities and penalties upon persons and
entities, such as the Working Interest Owners, for any discharges of petroleum
products in reportable quantities, for the costs of removing an oil spill, and
for natural resource damages. State laws for the control of water pollution also
provide varying civil and criminal penalties and liabilities in the case of a
release of petroleum or its derivatives in surface waters. The federal NPDES
permits prohibit the discharge of produced water, sand and other substances
related to the oil and gas industry to coastal waters of Louisiana and Texas.
Although the cost to reformat operations to comply with these zero discharge
mandates under federal or state law may be significant, the entire industry will
experience similar costs. The Working Interest Owners believe that these costs
will not have a material adverse impact on their operations.
AIR EMISSIONS
Amendments to the federal Clean Air Act were enacted in late 1990 and
require most industrial operations in the United States, including offshore
operations, to incur future capital expenditures in the next several years for
air emission control equipment in connection with maintaining and obtaining
operating permits and approvals addressing other air emission related issues.
The Environmental Protection Agency ("EPA") and state environmental agencies
have been developing regulations to implement these requirements. Some of the
Working Interest Owners' facilities are included within the categories of
hazardous air pollutant sources which will be affected by these regulations and
these regulations could make operation of the Royalty Properties more costly.
SOLID WASTE
The Working Interest Owners' operations may generate wastes that are
subject to the federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The EPA has limited disposal options for certain
hazardous wastes and may adopt more stringent disposal standards for
nonhazardous wastes. Furthermore, it is possible that some wastes that are
currently classified as nonhazardous, perhaps including wastes generated during
drilling and production operations, may in the future be designated as
"hazardous wastes". Such changes in the regulations would result in more
rigorous and costly disposal requirements which could result in increased
operating expenses on the Royalty Properties.
NORM
Oil and gas exploration and production activities have been identified as
generators of low-level naturally-occurring radioactive materials ("NORM").
The generation, handling and disposal of NORM in the course of offshore oil and
gas exploration and production activities is currently regulated in federal and
state waters. These regulations could result in an increase in operating
expenses on the Royalty Properties.
SUPERFUND
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to the fault or the legality of the original conduct, on certain classes
of persons that contributed to the release of a "hazardous substance" into the
environment. These persons include the current or previous owner and operator of
a facility and companies that disposed or arranged for the disposal of the
hazardous substance found at a facility. CERCLA also authorizes the EPA and, in
some cases, private parties to take actions in response to threats to the public
health or the environment and to seek recovery from such responsible classes of
persons of the costs, which can be substantial, of such action. Although
"petroleum" is excluded from CERCLA's definition of a
23
<PAGE>
"hazardous substance", in the course of their operations, the Working Interest
Owners may generate wastes that fall within CERCLA's definition of "hazardous
substances." The Working Interest Owners may be responsible under CERCLA for
all or part of the costs to clean up facilities at which such substances have
been disposed. Such clean-up costs may make operation of the Royalty Properties
more expensive for the Working Interest Owners.
OFFSHORE OPERATIONS
Offshore oil and gas operations are subject to regulations of the United
States Department of the Interior, including regulations promulgated pursuant to
the Outer Continental Shelf Lands Act, which impose liability upon a lessee,
such as the Working Interest Owners, under a federal lease for the cost of
clean-up of pollution resulting from a lessee's operations. In the event of a
serious incident of pollution, the Department of the Interior may require a
lessee under federal leases to suspend or cease operations in the affected
areas.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this Form 10-K.
ITEM 3. LEGAL PROCEEDINGS.
There are no material pending legal proceedings to which the Trust is a
party.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the
fourth quarter of 1997.
24
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Units were traded on the National Association of Securities Dealers
Automated Quotation System ("NASDAQ") SmallCap Market under the symbol TELOZ
prior to October 22, 1996. On October 22, 1996, the Trust Units were delisted
from the NASDAQ SmallCap Market. The Trust has been advised by NASDAQ that the
Trust Units are being traded on the OTC Bulletin Board. The Trust Units may also
be traded on pink sheets. The high and low sales price as reported by NASDAQ and
the OTC Bulletin Board, as applicable, for each quarter for the years ended
December 31, 1997 and 1996, were as follows:
SALES PRICES
------------------------------------------
1997 1996
-------------------- --------------------
QUARTER HIGH LOW HIGH LOW
- ------------------------------------ --------- --------- --------- ---------
First............................... $ 1.688 $ 1.250 $ 1.000 $ 0.750
Second.............................. $ 3.750 $ 1.323 $ 1.313 $ 0.750
Third............................... $ 4.500 $ 2.375 $ 1.438 $ 0.750
Fourth.............................. $ 5.375 $ 4.313 $ 1.500 $ 0.875
Sales prices on the OTC Bulletin Board reflect inter-dealer prices, without
retail mark-up, mark-down or commission, and may not necessarily represent
actual transactions.
The distributions paid each quarter for the years ended December 31, 1997
and 1996, were as follows:
DISTRIBUTION PAID
-------------------------------
QUARTER 1997 1996
- ------------------------------------- ------------- -------------
First................................ $ .155052 $ .000000
Second............................... $ .392365 $ .000000
Third................................ $ .316595 $ .124258
Fourth............................... $ .410961 $ .000000
At March 20, 1998, the 4,751,510 Units outstanding were held by 2,612 Unit
holders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------
1997 1996 1995 1994 1993
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Royalty income....................... $ 7,003,259 $ 785,708 $ 1,383,458 $ 3,435,312 $ 2,260,737
Distributable income................. $ 6,058,057 $ 590,417 $ 614,836 $ 2,650,823 $ 1,668,678
Distributions per Unit............... $ 1.274973 $ .124258 $ .129396 $ .557889 $ .351020
Total assets at year end............. $ 4,128,590 $ 1,818,212 $ 2,333,224 $ 2,412,692 $ 2,809,076
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
The Trust's source of capital is the Royalty income received from its share
of the Net Proceeds from the Royalty Properties. Reference is made to Note 9 in
the Notes to Financial Statements under Item 8 of this Form 10-K, which contains
certain unaudited supplemental reserve information, for an estimate of future
Royalty income attributable to the Partnership, of which the Trust has a 99.99%
interest.
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 gas, weather, industrial growth,
conservation measures, competition and other variables.
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
25
<PAGE>
contingent or future obligations of the Trust, are distributed currently to the
Unit holders. In 1994, in anticipation of future periods when the cash received
from the Royalty may not be sufficient for payment of Trust expenses, the Trust
determined, in accordance with the Trust Agreement, to begin further increasing
the Trust's cash reserve each quarter by an amount equal to the difference
between $200,000 and the amount of the Trust's general and administrative
expenses for such quarter. During 1994 and 1995, the aggregate amount of cash
reserved by the Trust was $347,638 and $370,258, respectively. During 1996, the
Trust used $397,845 from the Trust's cash reserve account to pay the Trust's
general and administrative expenses for the first, second and fourth quarters,
when no royalty income was received by the Trust. In the third quarter of 1996,
when royalty income was received, the Trust deposited $99,536 into the Trust's
cash reserve account. Therefore, the net cash used from the Trust's cash reserve
account in 1996 was $298,309. During 1997, the aggregate amount of cash reserved
by the Trust was $593,066. The total amount of the Trust's cash reserve at
December 31, 1997 was $1,472,689. In addition, in the first quarter of 1998, the
Trust has determined that the Trust's cash reserve is currently sufficient to
provide for future administrative expenses in connection with the winding up of
the Trust. The Trust has determined that a cash reserve equal to three times the
average expenses of the Trust during each of the past three fiscal years is
sufficient at this time to provide for future administrative expenses in
connection with the winding up of the Trust. This reserve amount for 1998 will
be $1,366,035. The excess amount of $106,654 will be distributed to Unit
holders, and no deposits are expected to be made to the Trust's cash reserve
account during 1998.
OPERATIONS
YEARS 1997 AND 1996
Royalty income increased approximately 791% from $785,708 in 1996 to
$7,003,259 in 1997 primarily due to a significant increase in gas and crude oil
and condensate revenues and a significant decrease in capital expenditures in
1997 on Ship Shoal 182/183 and West Cameron 643, as discussed below.
For 1997, the Trust had an undistributed net income of approximately
$952,683 compared to undistributed net loss of approximately $831,175 in 1996.
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 period that were applied to an existing loss carryforward. The
undistributed net income for 1997 was applied to a loss carryforward that
resulted from drilling wells on the Ship Shoal 182/183 property in 1996 and the
Eugene Island 348 gas imbalance settlement in 1994, as discussed below.
Volumes and dollar amounts discussed below represent amounts recorded by
the Working Interest Owners unless otherwise specified.
NATURAL GAS AND GAS PRODUCTS
Gas revenues increased approximately 31% from $14,293,083 in 1996 to
$18,680,941 in 1997, due primarily to a 16% increase in the average price
received for natural gas from $2.32 per Mcf in 1996 to $2.69 per Mcf in 1997. In
addition, gas volumes sold increased approximately 13% from 6,164,224 Mcf in
1996 to 6,990,809 Mcf in 1997. The increase in volumes was primarily
attributable to production from two wells on the West Cameron 643 property which
were drilled in 1996.
Chevron has advised the Trust that as of October 31, 1997 approximately
109,900 Mcf had been overtaken by Chevron from the Eugene Island 339 property.
The Partnership's share of revenues related to the overtaken gas was included in
the Partnership's Royalty income in the periods during which the gas was sold.
Accordingly, the reserves and future Royalty income attributable to the
Partnership, as discussed in the De Golyer and MacNaughton letter and shown in
Note 9 in the Notes to Financial Statements under Item 8 of this Form 10-K, have
been reduced by the Partnership's share of such imbalance. The standardized
measure of discounted future Royalty income attributable to the Partnership was
reduced by approximately
26
<PAGE>
$73,600 in 1997 related to such imbalance. Chevron has advised the Trust that
sufficient gas reserves exist on Eugene Island 339 for underproduced parties to
recoup their share of the gas imbalance on that property.
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 $166,100 and $5,000 was recovered from the Trust by the Working
Interest Owner during 1997 and 1996, respectively, 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.
CRUDE OIL AND CONDENSATE
Crude oil and condensate revenues increased approximately 120% from
$13,658,155 in 1996 to $30,018,655 in 1997 due primarily to a 94% increase in
crude oil and condensate volumes from 769,722 barrels in 1996 to 1,496,617
barrels in 1997. This increase in volumes was primarily attributable to
production from three of the wells drilled in 1996 on the Ship Shoal 182/183
property. In addition, there was a 13% increase in the average price received
from $17.74 per barrel in 1996 to $20.06 per barrel in 1997.
OPERATING AND CAPITAL EXPENDITURES
Operating expenses increased approximately 14% from $5,472,554 in 1996 to
$6,243,109 in 1997 due primarily to a workover on the E-9 well on the Ship Shoal
182/183 property in the first quarter of 1997 and the drilling of the B-15 well
on the Ship Shoal 182/183 property in the third quarter of 1997.
Capital expenditures decreased approximately 53% from $15,786,374 in 1996
to $7,379,553 in 1997 due primarily to six workovers and the drilling of the B-5
and B-9 sidetrack wells on the West Cameron 643 property and the drilling of the
F-2, B-11, B-12 and B-13 wells on the Ship Shoal 182/183 property in 1996.
SPECIAL COST ESCROW ACCOUNT
The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the leases, as well as for the estimated amount of future drilling
projects and other capital expenditures on the Royalty Properties. As provided
in the Conveyance, the amount of funds to be reserved is determined based on
factors including estimates of aggregate future production costs, aggregate
future Special Costs, aggregate future net revenues and actual current net
proceeds. Deposits into this account reduce current distributions and are placed
in an escrow account and invested in short-term certificates of deposit. Such
account is herein referred to as the "Special Cost Escrow Account". The
Trust's share of interest generated from the Special Cost Escrow Account,
approximately $215,900 in 1997, serves to reduce the Trust's share of allocated
production costs. Special Cost Escrow Account 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 Account 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
paid. Amounts in the Special Cost Escrow account will also be released when the
balance in such account exceeds 125% of future Special Costs. The discussion of
the terms of the Conveyance and Special Cost Escrow Account contained herein is
qualified in its entirety by reference to
27
<PAGE>
the Conveyance itself, which is an exhibit to this Form 10-K and is available
upon request from the Corporate Trustee.
In the first quarter of 1998, there was a net release of funds from the
Special Cost Escrow Account of approximately $513,800. The release was primarily
a result of a decrease in the current estimate of projected capital expenditures
of the Royalty Properties.
In 1997, the Working Interest Owners deposited a net amount of
approximately $554,500 into the Special Cost Escrow Account. The deposit was
made primarily due to an increase in the estimate of projected capital
expenditures, production costs and abandonment costs of the Royalty Properties.
As of December 31, 1997, approximately $4,622,000 remained in the Special Cost
Escrow Account.
In 1996, the Working Interest Owners deposited approximately $1,496,000
into the Special Cost Escrow Account. The deposit was made primarily due to an
increase in the estimate of projected capital expenditures, production costs and
abandonment costs of the Royalty Properties. As of December 31, 1996,
approximately $4,068,000 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.
SUMMARY BY PROPERTY
Listed below is a summary of 1997 operations as compared to 1996 of the
three principal Royalty Properties based on gross revenues generated.
EUGENE ISLAND 339
Eugene Island 339 crude oil revenues decreased from $9,482,584 in 1996 to
$5,401,845 in 1997 primarily due to a decrease in volumes from 547,768 barrels
in 1996 to 292,657 barrels in 1997. The decrease in volumes was primarily
attributable to an upward one-time well adjustment of 187,000 barrels on the
B-13 well in the first quarter of 1996 and a continued natural production
decline on this property. This decrease in production was partially offset by an
increase in the average crude oil price from $17.31 per barrel in 1996 to $18.46
per barrel in 1997. Gas revenues decreased from $1,262,583 in 1996 to $957,846
in 1997, primarily due to a decrease in gas volumes from 492,589 Mcf in 1996 to
351,775 Mcf for the same period in 1997. The decrease in gas volumes was due
primarily to a well being shut down during the first and second quarters of 1997
for upgrading the facility and compressor repair. The decrease in gas volumes
was slightly offset by an increase in the average price received for natural gas
from $2.57 per Mcf in 1996 to $2.80 per Mcf in 1997. Operating expenses
increased from $1,398,434 in 1996 to $1,987,731 in 1997 due primarily to service
facility credits on this property in the first and third quarters of 1996 and
service facility charges in the second quarter of 1997.
As discussed under "Description of the Royalty Properties -- Reserves,"
the Working Interest Owner has advised the Trust that as of October 31, 1997
there was an overtake imbalance position of approximately 109,900 Mcf (27,475
Mcf net to the Trust) on this property. Accordingly, gas revenues from this
property may be reduced in future periods while underproduced parties recoup
their share of the gas imbalance.
The Working Interest Owner has advised the Trust that it drilled the B-7
and B-9 wells in the fourth quarter of 1997 at a cost of approximately
$2,464,000 ($616,000 net to the Trust). The wells were unsuccessful. The Working
Interest Owner has also advised the Trust that it drilled the B-12 well in
January 1998, that the well was unsuccessful, and that they plan to drill the
B-4 and B-16 sidetrack wells in early 1998 at an aggregate cost of approximately
$4,075,000 ($1,018,750 net to the Trust).
SHIP SHOAL 182/183
Ship Shoal 182/183 crude oil revenues increased from $4,028,455 in 1996 to
$24,329,563 in 1997 primarily due to an increase in crude oil production from
214,984 barrels in 1996 to 1,189,636 barrels in
28
<PAGE>
1997. The increase in crude oil production was due primarily to the successful
drilling of the B-11, B-12 and B-13 wells in the first three quarters of 1996.
In addition, there was an increase in the average crude oil price from $18.74
per barrel in 1996 to $20.45 per barrel in 1997. Gas revenues increased from
$749,550 in 1996 to $5,276,887 in 1997 due primarily to an increase in gas
volumes from 302,175 Mcf in 1996 to 2,046,588 Mcf in 1997. The increase in gas
volumes was also primarily due to the successful drilling of the B-11, B-12 and
B-13 wells above and the B-15 well. In addition, there was an increase in the
average natural gas sales price from $2.53 per Mcf in 1996 to $2.64 per Mcf in
1997. Operating expenses increased from $1,517,217 in 1996 to $1,998,890 in 1997
due primarily to a workover in the E-9 well in the first quarter of 1997 and the
drilling of the B-15 well in the third quarter of 1997. Capital expenditures
decreased from $8,327,744 in 1996 to $4,817,257 in 1997 due primarily to the
drilling of the F-2 delineation gas well and the B-11, B-12 and B-13
developmental oil wells in the first nine months of 1996.
The Working Interest Owner has advised the Trust that approximately 71,823
Mcf have been overtaken by the Working Interest Owner from this property. The
Trust's share of this overtake position is approximately 17,956 Mcf.
Accordingly, gas revenues from this property may be reduced in future periods
while underproduced parties recover their share of the gas imbalance.
The Working Interest Owner has advised the Trust that it plans to drill a
delineation well on this property in late 1998 at an estimated cost of
approximately $2.5 million ($625,000 net to the Trust).
WEST CAMERON 643
West Cameron 643 gas revenues decreased from $11,519,699 in 1996 to
$11,121,313 in 1997 due primarily to a decrease in gas volumes from 5,047,450
Mcf in 1996 to 4,093,126 Mcf in 1997. The decrease in gas volumes was due to
depletion of the B-8 well. The decrease in volumes was offset by an increase in
the average price received for natural gas from $2.28 per Mcf in 1996 to $2.72
per Mcf in 1997. Operating expenses increased from $1,585,224 in 1996 to
$1,775,710 in 1997, due primarily to platform repairs in the fourth quarter
1997. Capital expenditures decreased from $6,845,744 in 1996 to $379,637 in 1997
due primarily to the 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 and the
drilling of the B-5, B-8 and B-9 sidetrack wells in the second quarter of 1996.
YEARS 1996 AND 1995
Royalty income decreased approximately 43% from $1,383,458 in 1995 to
$785,708 in 1996 primarily due to significant 1996 capital expenditures by the
Working Interest Owners on Ship Shoal 182/183 and West Cameron 643, as discussed
below.
For 1996, the Trust had an undistributed net loss of approximately $831,175
compared to undistributed net income of approximately $123,296 in 1995.
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 period that were applied to an existing loss carryforward. The
undistributed net loss for 1996 was primarily related to significant 1996
capital expenditures by Chevron on the Ship Shoal 182/183 property, as discussed
below.
Volumes and dollar amounts discussed below represent amounts recorded by
the Working Interest Owners unless otherwise specified.
NATURAL GAS AND GAS PRODUCTS
Gas revenues increased approximately 353% in 1996 as compared to 1995. Gas
volumes sold increased approximately 231% from 1,863,531 Mcf in 1995 to
6,164,224 Mcf in 1996, and the average price received for natural gas increased
40% from $1.66 per Mcf in 1995 to $2.32 per Mcf in 1996. The increase in volumes
was primarily attributable to production from three new wells on the West
Cameron 643 property.
29
<PAGE>
CRUDE OIL AND CONDENSATE
Crude oil and condensate revenues increased approximatley 69% from
$8,075,761 in 1995 to $13,658,155 in 1996 due primarily to a 53% increase in
crude oil and condensate volumes from 501,501 barrels in 1995 to 769,722 barrels
in 1996. This increase in volumes was primarily attributable to a well
adjustment of 187,000 barrels on the B-13 well on the Eugene Island 339 property
in the first quarter of 1996. In addition, there was a 10% increase in the
average price received from $16.10 per barrel in 1995 to $17.74 per barrel in
1996.
OPERATING AND CAPITAL EXPENDITURES
Operating expenses increased approximately 56% from $3,503,644 in 1995 to
$5,472,554 in 1996 due primarily to a compressor repair on the Ship Shoal
182/183 property in the first quarter of 1996, expenses incurred in connection
with the A-10 well workover on the West Cameron 643 property in the third
quarter of 1996 and costs incurred due to the installation of the remote
monitoring control equipment on the Eugene Island 339 property in the fourth
quarter of 1996.
Capital expenditures increased approximately 1779% from $839,964 in 1995 to
$15,786,374 in 1996 due primarily to six workovers and the drilling of the B-5
and B-9 sidetrack wells on the West Cameron 643 property and the drilling of the
F-2, B-11, B-12 and B-13 wells on the Ship Shoal 182/183 property in 1996.
In 1996, the Working Interest Owners deposited approximately $1,496,000
into the Special Cost Escrow Account. The deposit was made primarily due to an
increase in the current estimate of projected capital expenditures, production
costs and abandonment costs of the Royalty Properties. As of December 31, 1996,
approximately $4,068,000 remained in the Special Cost Escrow Account.
In 1995, the Working Interest Owners deposited a net amount of
approximately $207,000 into the Special Cost Escrow Account. The deposit was
made primarily due to an increase in the current estimate of projected capital
expenditures on the Royalty Properties. As of December 31, 1995, approximately
$2,572,000 remained in the Special Cost Escrow Account.
SUMMARY BY PROPERTY
Listed below is a summary of 1996 operations as compared to 1995 of the
three principal Royalty Properties based on gross revenues generated.
EUGENE ISLAND 339
Eugene Island 339 crude oil revenues increased from $3,800,360 in 1995 to
$9,482,584 in 1996 primarily due to an increase in volumes from 237,015 barrels
in 1995 to 547,768 barrels in 1996. The increase in volumes was primarily
attributable to an adjustment on the B-13 well in the first quarter of 1996. In
addition, there was an increase in the average price received from $16.03 per
barrel in 1995 to $17.31 per barrel in 1996. Gas revenues increased from
$1,005,792 in 1995 to $1,262,583 in 1996, primarily due to an increase in the
average natural gas sales price from $1.79 per Mcf in 1995 to $2.57 per Mcf in
1996. The increase in the average natural gas sales price was partially offset
by a decrease in gas volumes from 546,316 Mcf in 1995 to 492,589 Mcf in 1996.
The decrease in gas volumes was primarily due to the shut down of a booster
pumping station in the third quarter of 1996 and a continued natural production
decline on this property. Operating expenses decreased from $1,567,702 in 1995
to $1,398,434 in 1996 primarily due to a reduction in environmental compliance
costs in the first quarter of 1996 and service facilities credits on this
property in the first and third quarters of 1996.
WEST CAMERON 643
West Cameron 643 natural gas revenues increased from $910,018 in 1995 to
$11,519,699 in 1996 primarily due to an increase in volumes from 574,763 Mcf in
1995 to 5,047,450 Mcf in 1996. The increase in gas volumes was due to the
successful B-5, B-8 and B-9 wells drilled on this property in the second quarter
of 1996 and successful workovers on the A-2 and A-9 wells in the first quarter
of 1996. In addition, there was an increase in the average price received for
natural gas from $1.58 per Mcf in 1995 to $2.28 per Mcf in 1996. Operating
expenses increased from $349,890 in 1995 to $1,585,224 in 1996 due primarily to
30
<PAGE>
expenses incurred in the third quarter of 1996 in connection with the workover
on the A-10 well. Capital expenditures increased from $680,150 in 1995 to
$6,845,744 in 1996 due primarily to the 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 and the drilling of the B-5, B-8 and B-9 sidetrack wells in the second
quarter of 1996.
SHIP SHOAL 182/183
Ship Shoal 182/183 crude oil production decreased from 253,747 barrels in
1995 to 214,984 barrels in 1996 offset by an increase in crude oil average
prices from $16.17 per barrel in 1995 to $18.74 per barrel in 1996 resulted in a
decrease in crude oil revenues from $4,104,147 in 1995 to $4,028,455 in 1996.
The decrease in crude oil production was primarily due to a continued natural
production decline on this property. Gas revenues increased from $471,989 in
1995 to $749,550 in 1996 due primarily to an increase in the average natural gas
sales price from $1.74 per Mcf in 1995 to $2.53 per Mcf in 1996. In addition,
there was an increase in gas volumes from 269,861 Mcf in 1995 to 302,175 Mcf in
1996 due primarily to the C-10 well being watered out and the C-4 well being
sanded in during portions of the second, third, and fourth quarters of 1995 and
the successful recompletion of the E-1 well in the fourth quarter of 1996.
Operating expenses increased from $1,318,495 in 1995 to $1,517,217 in 1996 due
primarily to expenses incurred in the second quarter of 1996 in connection with
a compressor repair. Capital expenditures increased from $34,137 in 1995 to
$8,327,744 in 1996 due primarily to the drilling of the F-2 delineation gas well
and the B-11, B-12 and B-13 developmental oil wells in the first nine months of
1996.
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 royalties paid to the
Trust for 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.
<TABLE>
<CAPTION>
ROYALTY PROPERTIES
YEAR ENDED DECEMBER 31,(1)
-------------------------------------------
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Crude oil and condensate (bbls)................. 1,496,617 769,722 501,501
Natural gas and gas products (Mcf).............. 6,990,809 6,164,224 1,863,531
Crude oil and condensate average price, per
bbl........................................... $ 20.06 $ 17.74 $ 16.10
Natural gas average price, per Mcf (excluding
gas products)................................. $ 2.69 $ 2.32 $ 1.66
Crude oil and condensate revenues............... $30,018,655 $13,658,155 $ 8,075,761
Natural gas and gas products revenues........... 18,680,941 14,293,083 3,152,901
Production expenses............................. (7,275,354) (6,363,513) (3,533,524)
Capital expenditures............................ (7,379,553) (15,786,374) (839,964)
Undistributed net loss (income)(2).............. (3,810,733) 3,324,701 (493,182)
(Provision for) Refund of escrowed special
costs......................................... (2,218,120) (5,982,904) (827,608)
----------- ----------- -----------
NET PROCEEDS.................................... $28,015,836 $ 3,143,148 $ 5,534,384
Royalty interest................................ 25% 25% 25%
----------- ----------- -----------
Partnership share............................... 7,003,959 785,787 1,383,596
Trust interest.................................. 99.99% 99.99% 99.99%
----------- ----------- -----------
Trust share..................................... $ 7,003,259 $ 785,708 $ 1,383,458
=========== =========== ===========
</TABLE>
(FOOTNOTES ON FOLLOWING PAGE)
31
<PAGE>
- ------------
(1) Amounts represent actual production for the twelve month period ending on
October 31 of each year, 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 December 31, 1997, the loss
carryforward was $1,684,347 ($421,087 net to the Trust).
YEAR 2000
The Corporate Trustee utilizes software and technologies throughout its
operations that will be affected by the date change in the year 2000 ("Year
2000 Issue"). An assessment of the systems that will be affected by the Year
2000 Issue is underway. The Trust does not believe that the costs related to the
Year 2000 Issue will materially impact its operations. However, there can be no
guarantee that the systems of other companies, on which the Corporate Trustee's
systems rely, will be timely converted or that a failure to convert by another
company or a conversion that is incompatible with the Corporate Trustee's
systems would not have a material adverse effect on the Trust.
RECENT DEVELOPMENTS
In March 1998, Chevron advised the Trust that production should begin in
mid-April 1998 on the two wells on the East Cameron 371 property.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
32
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Trustees and Unit Holders of TEL Offshore Trust:
We have audited the accompanying statements of assets, liabilities and
trust corpus of TEL Offshore Trust as of December 31, 1997 and 1996, and the
related statements of distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 1997. These financial
statements are the responsibility of the Trustees. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As described in Note 3, these financial statements were prepared on a
comprehensive basis of accounting other than generally accepted accounting
principles.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of TEL
Offshore Trust as of December 31, 1997 and 1996, and its distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 1997, on the comprehensive basis of accounting described in Note 3.
ARTHUR ANDERSEN LLP
Houston, Texas
March 27, 1998
33
<PAGE>
TEL OFFSHORE TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1997 1996
------------ ------------
<S> <C> <C>
ASSETS
Cash and cash equivalents......................................................... $ 3,425,376 $ 879,623
Net overriding royalty interest in oil and gas properties, net of accumulated
amortization of $27,564,441 and $27,329,066 at December 31, 1997 and 1996,
respectively.................................................................... 703,214 938,589
------------ ------------
Total assets...................................................................... $ 4,128,590 $ 1,818,212
============ ============
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders.............................................. $ 1,952,687 $ 0
Reserve for future Trust expenses................................................. 1,472,689 879,623
Commitments and contingencies (Note 7)
Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding at
December 31, 1997 and 1996)..................................................... 703,214 938,589
------------ ------------
Total liabilities and trust corpus................................................ $ 4,128,590 $ 1,818,212
============ ============
STATEMENTS OF DISTRIBUTABLE INCOME
YEAR ENDED DECEMBER 31,
----------------------------------------
1997 1996 1995
------------ ------------ ------------
Royalty income.................................................. $ 7,003,259 $ 785,708 $ 1,383,458
Interest income................................................. 54,798 35,759 31,378
------------ ------------ ------------
7,058,057 821,467 1,414,836
General and administrative expenses............................. (406,934) (529,359) (429,742)
Decrease (Increase) in reserve for future Trust expenses........ (593,066) 298,309 (370,258)
------------ ------------ ------------
Distributable income............................................ $ 6,058,057 $ 590,417 $ 614,836
============ ============ ============
Distributions per Unit (4,751,510 Units)........................ $ 1.274973 $ .124258 $ .129396
============ ============ ============
STATEMENTS OF CHANGES IN TRUST CORPUS
YEAR ENDED DECEMBER 31,
------------------------------------------
1997 1996 1995
------------ ------------ --------------
Trust corpus, beginning of year................................ $ 938,589 $ 1,071,618 $ 1,343,475
Distributable income........................................... 6,058,057 590,417 614,836
Distributions to Unit holders.................................. (6,058,057) (590,417) (614,836)
Amortization of overriding royalty interest.................... (235,375) (133,029) (271,857)
------------ ------------ --------------
Trust corpus, end of year...................................... $ 703,214 $ 938,589 $ 1,071,618
============ ============ ==============
</TABLE>
The accompanying notes are an integral part of these financial statements.
34
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(1) TRUST ORGANIZATION AND PROVISIONS
Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL
Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of
Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December
22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership
("Partnership") was formed in which the Trust owns a 99.99% interest and
Tenneco Oil Company ("Tenneco") owned a .01% interest. In general, the Plan
was effected by transferring an overriding royalty interest ("Royalty")
equivalent to a 25% net profits interest in the oil and gas properties (the
"Royalty Properties") of Tenneco Exploration, Ltd. ("Exploration I") located
offshore Louisiana to the Partnership and issuing certificates evidencing units
of beneficial interest in the Trust 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 holders of units of beneficial interests.
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 replaced Pennzoil as
the Working Interest Owner of the East Cameron 354 and Eugene Island 367
properties, respectively, on October 1, 1995, and also assumed Pennzoil's
obligations under the Conveyance with respect to such properties.
All of the Royalty Properties continue to be subject to the Royalty, and it
is anticipated that the Trust and the Partnership will 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 to Financial Statements 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
35
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(1) TRUST ORGANIZATION AND PROVISIONS -- (CONTINUED)
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;
On January 14, 1983, Tenneco Offshore distributed units of beneficial
interest ("Units") in the Trust to holders of Tenneco Offshore's common stock
on the basis of one Unit for each common share owned on such date.
The terms of the Trust Agreement, dated January 1, 1983, provide, among
other things, that:
(a) the Trust is a passive entity and cannot engage in any business or
investment activity or purchase any assets;
(b) the interest in the Partnership can be sold in part or in total
for cash upon approval of a majority of the Unit holders;
(c) the Trustees, as defined below, can establish cash reserves and
borrow funds to pay liabilities of the Trust and can pledge the assets of
the Trust to secure payments of the borrowings. At December 31, 1991, a
cash reserve of $120,000 had been established for future Trust general and
administrative expenses. During 1992 and 1993, in anticipation of future
periods when the cash received from the Royalty may not be sufficient for
payment of Trust expenses, the reserve for future Trust general and
administrative expenses was increased each quarter by an amount equal to
the difference between $150,000 and the amount of the Trust's general and
administrative expenses for such quarter. In 1994 in anticipation of future
periods when the cash received from the Royalty may not be sufficient for
payment of Trust expenses, the Trust determined, in accordance with the
Trust Agreement, to begin further increasing the Trust's cash reserve each
quarter by an amount equal to the difference between $200,000 and the
amount of the Trust's general and administrative expenses for such quarter.
During 1994 and 1995, the aggregate amount of cash reserved by the Trust
was $347,638 and $370,258, respectively. During 1996, the Trust used
$397,845 from the Trust's cash reserve account to pay the Trust's general
and administrative expenses for the first, second and fourth quarters, when
no royalty income was received by the Trust. In the third quarter of 1996,
when Royalty income was received, the Trust reserved $99,536. Therefore,
the net cash used from the Trust's cash reserve account in 1996 was
$298,309. During 1997, the aggregate amount of cash reserved by the Trust
was $593,066. The total amount of the Trust's cash reserve at December 31,
1997 was $1,472,689. In addition, in the first quarter of 1998, the Trust
has determined that the Trust's cash reserve is currently sufficient to
provide for future administrative expenses in connection with the winding
up of the Trust. The Trust has determined that a cash reserve equal to
three times the average expenses of the Trust during each of the past three
fiscal years is sufficient at this time to provide for future
administrative expenses in connection with the winding up of the Trust.
This reserve amount for 1998 will be $1,366,035. The excess amount of
$106,654 will be distributed to Unit holders, and no deposits are expected
to be made to the Trust's cash reserve account during 1998.
(d) the Trustees will make cash distributions to the Unit holders in
January, April, July and October of each year as discussed in Note 4; and
(e) the Trust will terminate upon the first to occur of the following
events: (i) total future net revenues attributable to the Partnership's
interest in the Royalty, as determined by independent petroleum engineers,
as of the end of any year, are less than $2.0 million or (ii) a decision to
terminate the Trust by the affirmative vote of Unit holders representing a
majority of the Units. Future net
36
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(1) TRUST ORGANIZATION AND PROVISIONS -- (CONTINUED)
revenues attributable to the Royalty were estimated at $24.3 million as of
October 31, 1997. (See Note 9 for further information regarding estimated
future net revenues.) Upon termination of the Trust, the Corporate Trustee
will sell for cash all assets held in the Trust estate and make a final
distribution to the Unit holders of any funds remaining, after all Trust
liabilities have been satisfied.
The Trust is administered by Chase Bank of Texas, National Association
(formerly known as Texas Commerce Bank National Association) ("Corporate
Trustee") and George Allman, Jr., W. Leslie Duffy and Richard L. Melton
("Individual Trustees"), as trustees ("Trustees").
(2) 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 its 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 its oil and gas
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 a special cost reserve. The
Special Cost Reserve Account is 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.
Crude oil sales to Chevron accounted for approximately 32%, 85% and 73% of
crude oil revenues from the Royalty Properties during 1997, 1996 and 1995,
respectively. Chevron purchased crude oil at prices based on its own published
pricing bulletins with an adjustment for gravity and transportation charges.
Average monthly prices for fiscal 1997 ranged from $17.28 per bbl to $23.91 per
bbl. The average price of crude oil sold under this arrangement for February
1998 was approximately $13.95 per bbl. Sales to Texaco Inc. accounted for
approximately 68%, 14% and 24% of crude oil revenues from the Royalty Properties
during 1997, 1996 and 1995, respectively. Sales to Texaco Natural Gas Inc. and
NGC Corporation accounted for approximately 61% and 33%, respectively, of total
gas revenues from the Royalty Properties during 1997.
The Trust's share of Royalty income was reduced by approximately $473,900,
$373,500 and $120,000 in 1997, 1996 and 1995, respectively, for management fees
paid to the Working Interest Owners as reimbursement for expenses incurred by
them on behalf of the Trust. Such management fees were calculated as 3% of the
Trust's share of the sum of revenues, production expenses and capital
expenditures attributable to the Royalty Properties in each of the three years
above.
(3) BASIS OF ACCOUNTING
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 1.
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
37
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(3) BASIS OF ACCOUNTING -- (CONTINUED)
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
units-of-production basis, is charged directly to Trust corpus since such amount
does not affect distributable income.
Cash and cash equivalents include all highly liquid short-term investments
with original maturities of three months or less.
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) 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.
(5) SPECIAL COST ESCROW ACCOUNT
The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the Royalty Properties, as well as for the estimated amount of
future drilling projects and other capital expenditures on the Royalty
Properties. As provided in the Conveyance, the amount of funds to be reserved is
determined based on factors including estimates of aggregate future production
costs, aggregate future Special Costs, aggregate future net revenues and actual
current net proceeds. Deposits into this account reduce current distributions
and are placed in an escrow account and invested in short-term certificates of
deposit. Such account is herein referred to as the "Special Cost Escrow
Account". The Trust's share of interest generated from the Special Cost Escrow
Account, approximately $215,900, $150,700 and $112,500 for 1997, 1996 and 1995,
respectively, serves to reduce the Trust's share of allocated production costs.
As of December 31, 1997, 1996 and 1995, approximately $4,622,000, $4,068,000 and
$2,572,000 respectively, remained in the Special Cost Escrow Account. Special
Cost Escrow Account 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
Account 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 will also be released when the balance in such
account exceeds 125% of future Special Costs. The discussion of the terms of the
Conveyance and Special Cost Escrow Account contained herein is qualified in its
entirety by reference to the Conveyance itself, which is an exhibit to this Form
10-K and is available upon request from the Corporate Trustee.
In the first quarter of 1998, there was a net release of funds from the
Special Cost Escrow Account of approximately $513,800. The release was primarily
a result of a decrease in the current estimate of
38
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(5) SPECIAL COST ESCROW ACCOUNT -- (CONTINUED)
projected capital expenditures of the Royalty Properties. 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.
In 1997, the Working Interest Owners deposited a net amount of
approximately $554,500 into the Special Cost Escrow Account. The deposit was
made primarily due to an increase in the current estimate of projected capital
expenditures, production costs and abandonment costs of the Royalty Properties.
In 1996, the Working Interest Owners deposited approximately $1,496,000
into the Special Cost Escrow Account. The deposit was made primarily due to an
increase in the current estimate of projected capital expenditures, production
costs and abandonment costs of the Royalty Properties.
In 1995, the Working Interest Owners deposited a net amount of
approximately $207,000 into the Special Cost Escrow Account. The deposit was
made primarily due to an increase in the current estimate of projected capital
expenditures on the Royalty Properties.
(6) FEDERAL INCOME TAX MATTERS
The Internal Revenue Service has ruled that the Trust is a grantor trust
and therefore the Trust will incur no federal income tax liability.
(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 $166,100, $5,000 and $150,000 was recovered from the Trust by the
Working Interest Owner during 1997, 1996 and 1995, respectively, 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.
(8) SUBSEQUENT EVENT
Effective January 1, 1998, Energy Resource Technology, Inc. ("Energy")
acquired the East Cameron 354 property from SONAT. As a result of such
acquisition, Energy replaced SONAT as the Working Interest Owner of the East
Cameron 354 property effective January 1, 1998, and also assumed SONAT's
obligations under the Conveyance with respect to such property.
(9) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Estimates of the proved oil and gas reserves attributable to the
Partnership's royalty interest are based on a report prepared by DeGolyer and
MacNaughton, independent petroleum engineering consultants. Estimates were
prepared in accordance with guidelines established by the Securities and
Exchange Commission and the Financial Accounting Standards Board. Accordingly,
the estimates are based on
39
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(9) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
existing economic and operating conditions in effect at October 31, 1997, with
no provision for future increases or decreases except for periodic price
redeterminations in accordance with existing gas contracts.
The reserve volumes and revenue values attributable to the Partnership's
royalty interest were estimated from projections of reserves and revenue
attributable to the combined interests consisting of the Partnership's royalty
interest and the retained interest of the Working Interest Owners in the Royalty
Properties. Net reserves attributable to the Partnership's royalty interest were
estimated by allocating to the Partnership a portion of the estimated combined
net reserves of the subject properties based on the ratio of the Partnership's
interest in future net revenues to combined future gross revenues. Because the
net reserve volumes attributable to the Partnership's royalty interest are
estimated using an allocation of reserves based on estimates of future revenue,
a change in prices or costs will result in changes in the estimated net
reserves. Therefore, the estimated net reserves attributable to the
Partnership's royalty interest will vary if different future price and cost
assumptions are used. All reserves attributable to the Partnership's royalty
interest are located in the United States.
The Partnership's share of gas sales are recorded by the Working Interest
Owners on the cash method of accounting. Under this method, revenues are
recorded based on actual gas volumes sold which could be more or less than the
volumes the Working Interest Owners are entitled to based on their ownership
interests. The Partnership's Royalty income for a period reflects the actual gas
sold during the period. Chevron has advised the Trust that as of October 31,
1997, approximately 109,900 Mcf were overtaken by Chevron from the Eugene Island
339 property in prior periods. The Partnership's share of revenue related to the
overtaken gas was included in the Partnership's Royalty income in the periods
during which the gas was sold. Accordingly, the reserves and future Royalty
income attributable to the Partnership, as discussed in the DeGolyer and
MacNaughton letter, have been reduced by the Partnership's share of such
imbalance. The standardized measure of discounted future Royalty income
attributable to the Partnership was reduced by approximately $73,600 in 1997
related to such imbalance. Chevron has advised the Trust that sufficient gas
reserves exist on Eugene Island 339 for underproduced parties to recoup their
share of the gas imbalance on that property.
Distributable income for the Partnership for the periods ended December 31,
1997, 1996 and 1995 included net proceeds relating to production of reserves
from the Royalty Properties for the twelve months ended October 31, 1997, 1996
and 1995, respectively. Accordingly, all reserve information included in the
tables below is as of October 31, 1997, 1996 and 1995.
40
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(9) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
Estimated net proved reserves attributable to the Partnership's royalty
interest for the periods indicated, are as follows:
<TABLE>
<CAPTION>
PARTNERSHIP
-------------------------
CRUDE OIL
AND NATURAL
CONDENSATE GAS
(BBLS) (MCF)
---------- ----------
<S> <C> <C>
Proved Developed and Undeveloped Reserves:
October 31, 1994................................................................... 223,067 1,890,489
Revisions of previous estimates(a)................................................. 185,986 (216,130)
Royalty production................................................................. (73,078) (235,036)
---------- ----------
October 31, 1995................................................................... 335,975 1,439,323
Additional disclosures:
Reserves related to Pennzoil(d)................................................. (457) (110,567)
---------- ----------
October 31, 1995, net of reserves related to Pennzoil........................... 335,518 1,328,756
========== ==========
October 31, 1995................................................................... 335,975 1,439,323
Revisions of previous estimates(a)................................................. 687,725 4,041,561
Extensions, discoveries and other additions........................................ 86,752 984,560
Royalty production................................................................. (192,431) (1,571,919)
---------- ----------
October 31, 1996................................................................... 918,021 4,893,525
Additional disclosures:
Reserves related to Pennzoil(d)................................................. (820) (28,172)
---------- ----------
October 31, 1996, net of reserves related to Pennzoil........................... 917,201 4,865,353
========== ==========
October 31, 1996................................................................... 918,021 4,893,525
Revisions of previous estimates(a)................................................. 146,239 63,599
Extensions, discoveries and other additions........................................ 11,887 221,520
Royalty production................................................................. (374,154) (1,782,704)
---------- ----------
October 31, 1997................................................................... 701,993 3,395,940
Additional disclosures:
Reserves related to Pennzoil(d)................................................. (2,292) (94,891)
---------- ----------
October 31, 1997, net of reserves related to Pennzoil........................... 699,701 3,301,049
========== ==========
Proved Developed Reserves:
October 31, 1994, net of reserves related to Pennzoil(d)........................... 219,394 1,612,177
========== ==========
October 31, 1995................................................................... 201,110 922,502
Additional disclosures:
Reserves related to Pennzoil(d)................................................. (457) (110,567)
---------- ----------
October 31, 1995, net of reserves related to Pennzoil........................... 200,653 811,935
========== ==========
October 31, 1996................................................................... 917,883 4,885,185
Additional disclosures:
Reserves related to Pennzoil(d)................................................. (820) (28,172)
---------- ----------
October 31, 1996, net of reserves related to Pennzoil........................... 917,063 4,857,013
October 31, 1997................................................................... 695,022 3,169,790
Additional disclosures:
Reserves related to Pennzoil(d)................................................. (2,292) (94,891)
---------- ----------
October 31, 1997, net of reserves related to Pennzoil........................... 692,730 3,074,899
========== ==========
</TABLE>
(SEE NOTES ON FOLLOWING PAGE)
41
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(9) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
The following table sets forth estimates of the standardized measure of
discounted future Royalty income (based upon a discount rate of 10 percent) from
estimated future production of proved oil and gas reserves attributable to the
Partnership as of October 31, 1997, 1996 and 1995:
1997 1996 1995
--------- --------- ---------
(THOUSANDS)
Future Royalty income................ $ 24,285 $ 30,903 $ 7,693
Discount at 10% per annum............ (3,825) (6,352) (2,168)
--------- --------- ---------
Standardized measure of discounted
future Royalty income from proved
oil and gas reserves, discounted at
10% per annum(c)................... 20,460 24,551 5,525
Additional disclosures:
Amounts attributable to
Pennzoil(d)..................... (250) (77) (140)
--------- --------- ---------
Standardized measure of discounted
future Royalty income from
proved oil and gas reserves,
discounted at 10% per annum, net
of amounts attributable to
Pennzoil(c)..................... $ 20,210 $ 24,474 $ 5,385
========= ========= =========
The following table summarizes the changes in the standardized measure of
discounted future Royalty income for the Partnership for the twelve months ended
October 31, 1997, 1996 and 1995:
1997 1996 1995
--------- --------- ---------
(THOUSANDS)
Beginning balance(c)................. $ 24,551 $ 5,525 $ 5,145
Revisions of previous
estimates(a).................... 152 16,426 1,997
Extensions, discoveries and other
additions....................... 745 2,825 --
Royalty income..................... (7,003) (786) (1,383)
Accretion of discount.............. 2,455 553 515
Other(b)........................... (440) 8 (749)
--------- --------- ---------
Net changes in standardized
measure................... (4,091) 19,026 380
--------- --------- ---------
Ending balance(c).................... 20,460 24,551 5,525
Additional disclosures:
Amounts attributable to
Pennzoil(d)..................... (250) (77) (140)
--------- --------- ---------
Ending balance, net of amounts
attributable to Pennzoil(c)..... $ 20,210 $ 24,474 $ 5,385
========= ========= =========
- ------------
NOTES:
(a) Primarily represents net effect of changes in prices, cost estimates and
reserve quantity revisions attributable to the Royalty Properties on the
royalty computation.
(b) Primarily represents changes in estimated timing of production and changes
in the Special Cost Escrow Account.
(c) Future income taxes are not applicable for purposes of these estimates since
the Partnership is a nontaxable entity.
(d) As a result of the imbalance settlement by Pennzoil, discussed in Note 7,
the associated volumes and future royalty income related to the Pennzoil
owned properties have been excluded from the Trust's Supplemental Reserve
Information, beginning in 1994.
42
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(10) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
SUMMARIZED QUARTERLY RESULTS
THREE MONTHS ENDED*
----------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Year Ended December 31, 1997:
Royalty income......................... $ 1,126,005 $ 2,051,820 $ 1,690,234 $ 2,135,200
Distributable income................... $ 736,735 $ 1,864,327 $ 1,504,308 $ 1,952,687
Distributions per Unit................. $ .155052 $ .392365 $ .316595 $ .410961
Year Ended December 31, 1996:
Royalty income......................... $ 0 $ 0 $ 785,708 $ 0
Distributable income................... $ 0 $ 0 $ 590,417 $ 0
Distributions per Unit................. $ .000000 $ .000000 $ .124258 $ .000000
</TABLE>
- ------------
* Royalty income and distributable income were decreased or increased in certain
quarters due to deposits to or releases from the Special Cost Escrow Account
as discussed in Note 5 above.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
43
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant. The
Trustees consist of a Corporate Trustee and three Individual Trustees. Any
Trustee may be removed by the affirmative vote of two Individual Trustees or by
the affirmative vote of a majority of the Units at a meeting of Unit holders of
beneficial interest in the Trust at which a quorum is present.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS.
As of March 20, 1998, no person was known to be the beneficial owner of
more than five percent of the Units of beneficial interest in the Trust.
(B) SECURITY OWNERSHIP OF MANAGEMENT.
Not applicable.
(C) CHANGES IN CONTROL.
Registrant knows of no arrangements, including the pledge of securities of
the Registrant, the operation of which may at a subsequent date result in a
change in control of the Registrant.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Each of the Working Interest Owners owns interests, for its own account, in
leases which are in the same area as leases in which the Partnership has
acquired or may acquire an interest. Such relationships may give rise to
potential conflicts of interests in, among other things, the operation of such
leases and in the acquisition and operation of any drainage leases acquired by a
Working Interest Owner for its own account. Additionally, the Working Interest
Owners and their affiliates are not prohibited from purchasing oil and gas
produced from or attributable to any leases in which the Partnership has an
interest. Prior to the sale to Chevron, Tenneco also owned interests, for its
own account, in leases in the same area as leases in which the Partnership has
an interest.
Crude oil sales to the Supply and Distribution Department of Texaco, Inc.
and Chevron accounted for approximately 68% and 32%, respectively, of total
crude oil revenues from the Royalty Properties during 1997.
The Trust's share of Royalty income was reduced by approximately $473,900
in 1997 for management fees paid to the Working Interest Owners as reimbursement
for expenses incurred by them on behalf of the Trust. The aggregate amount of
management fees paid to the Working Interest Owners was calculated as 3% of the
Trust's share of the sum of revenues, production expenses and capital
expenditures attributable to the Royalty Properties in 1997.
Effective August 31, 1996, Chevron's Natural Gas Business Unit and Warren
Petroleum Company merged with NGC Corporation In connection with such merger,
Chevron became one of three principal stockholders of NGC Corporation, and all
of Chevron's natural gas and natural gas liquids relative to the Trust's Royalty
Properties have been committed and are being sold to NGC Corporation.
44
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) (1) FINANCIAL STATEMENTS
The following financial statements are set forth under Part II, Item 8 of
this Annual Report on Form 10-K on the pages as indicated:
PAGE IN THIS
FORM 10-K
Report of Independent Public Accountants...................... 33
Statements of Assets, Liabilities and Trust Corpus............ 34
Statements of Distributable Income............................ 34
Statements of Changes in Trust Corpus......................... 34
Notes to Financial Statements................................. 35
(A) (2) SCHEDULES
Schedules have been omitted because they are not required, not applicable
or the information required has been included elsewhere herein.
(A) (3) EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference).
<TABLE>
<CAPTION>
SEC FILE OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------- -------
<S> <C> <C>
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 year ended December
31, 1992 of TEL Offshore Trust).......................................... 0-6910 4(a)
4(b)* Agreement of General Partnership of TEL Offshore Trust Partnership
between Tenneco Oil Company and the TEL Offshore Trust, dated January 1,
1983 (Exhibit 4(b) to Form 10-K for year ended December 31, 1992 of TEL
Offshore Trust).......................................................... 0-6910 4(b)
4(c)* Conveyance of Overriding Royalty Interests from Exploration I to the
Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992
of TEL Offshore Trust)................................................... 0-6910 4(c)
4(d)* Amendments to TEL Offshore Trust Trust Agreement, dated December 7, 1984
(Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL
Offshore Trust).......................................................... 0-6910 4(d)
4(e)* Amendment to the Agreement of General Partnership of TEL Offshore Trust
Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K
for year ended December 31, 1992 of TEL Offshore Trust).................. 0-6910 4(e)
10(a)* Purchase Agreement, dated as of December 7, 1984 by and between Tenneco
Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K
for year ended December 31, 1992 of TEL Offshore Trust).................. 0-6910 10(a)
10(b)* Consent Agreement, dated November 16, 1988, between TEL Offshore Trust
and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended
December 31, 1988 of TEL Offshore Trust)................................. 0-6910 10(b)
10(c)* Assignment and Assumption Agreement, dated November 17, 1988, between
Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form
10-K for year ended December 31, 1988 of TEL Offshore Trust)............. 0-6910 10(c)
10(d)* Gas Purchase and Sales Agreement Effective September 1, 1993 between
Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company
(Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of TEL
Offshore Trust).......................................................... 0-6910 10(d)
27(a) Financial Data Schedule
</TABLE>
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange
Commission during the fourth quarter of 1997.
45
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) 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 ON THIS DAY OF MARCH,
1998.
TEL OFFSHORE TRUST
By CHASE BANK OF TEXAS, NATIONAL
ASSOCIATION, CORPORATE TRUSTEE
By /s/ PETE FOSTER
PETE FOSTER
SENIOR VICE PRESIDENT
& TRUST OFFICER
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE DATE
CHASE BANK OF TEXAS, NATIONAL
ASSOCIATION, Corporate Trustee
By/s/PETE FOSTER March , 1998
PETE FOSTER
SENIOR VICE PRESIDENT
& TRUST OFFICER
INDIVIDUAL TRUSTEES
/s/GEORGE ALLMAN, JR. March , 1998
GEORGE ALLMAN, JR., TRUSTEE
/s/W. LESLIE DUFFY March , 1998
W. LESLIE DUFFY, TRUSTEE
/s/RICHARD L. MELTON March , 1998
RICHARD L. MELTON, TRUSTEE
46
<PAGE>
THIS ANNUAL REPORT ON FORM 10-K WAS DISTRIBUTED TO UNIT HOLDERS AS AN
ANNUAL REPORT. ADDITIONAL COPIES OF THIS ANNUAL REPORT WILL BE PROVIDED, WITHOUT
CHARGE, AND COPIES OF EXHIBITS HERETO WILL BE PROVIDED, UPON PAYMENT OF A
REASONABLE FEE, UPON WRITTEN REQUEST FROM ANY HOLDER OF UNITS TO:
TEL Offshore Trust
Chase Bank of Texas, National Association, Trustee
Attention: Debbie Miller, Corporate Trust Department
P.O. Box 4717
Houston, Texas 77210-4717
AUDITORS COUNSEL TRANSFER AGENT AND REGISTRAR
Arthur Andersen LLP Andrews & Kurth L.L.P. American Stock Transfer
Houston, Texas Houston, Texas & Trust Co. as agent for
Chase Bank of Texas, N.A.
Houston, Texas
TEL OFFSHORE TRUST
P.O. Box 4717
Houston, Texas 77210-4717
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENT OF ASSETS, LIABILITIES, AND TRUST CORPUS AS OF DECEMBER 31,
1997 AND THE STATEMENT OF DISTRIBUTABLE INCOME FOR THE NINE MONTHS ENDED
DECEMBER 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 3,425,376
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3,425,376
<PP&E> 27,564,441
<DEPRECIATION> 4,128,590
<TOTAL-ASSETS> 1,952,687
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 703,214
<TOTAL-LIABILITY-AND-EQUITY> 4,128,590
<SALES> 7,058,057
<TOTAL-REVENUES> 0
<CGS> 0
<TOTAL-COSTS> 1,000,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 6,058,057
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 6,058,057
<EPS-PRIMARY> 1.274
<EPS-DILUTED> 1.274
</TABLE>
