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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, 1999
[ ] 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 17, 2000, of $4.50 was $21,381,795.
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 17, 2000, 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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Item 1. Business........................................................................................ 1
Description of the Trust...................................................................... 1
General..................................................................................... 1
History of the Trust........................................................................ 3
Description of the Units...................................................................... 5
Distributions............................................................................... 5
Possible Requirement that Units be Divested................................................. 5
Liability of Unit Holders................................................................... 6
Federal Income Tax Matters.................................................................. 6
Tax-Exempt Organizations.................................................................... 8
State Law Considerations.................................................................... 8
Termination of the Trust...................................................................... 8
Royalty Income, Distributable Income and Total Assets......................................... 9
Description of Royalty Properties............................................................. 9
Producing Acreage and Wells................................................................. 9
Reserves.................................................................................... 10
Operations and Production................................................................... 21
Marketing..................................................................................... 21
Gas Marketing............................................................................... 21
Oil Marketing............................................................................... 23
Competition and Regulation.................................................................... 24
Competition................................................................................. 24
Regulation -- General....................................................................... 24
FERC Regulations............................................................................ 24
State Regulation............................................................................ 24
Environmental Regulations................................................................... 24
Item 2. Properties...................................................................................... 26
Item 3. Legal Proceedings............................................................................... 26
Item 4. Submission of Matters to a Vote of Security Holders............................................. 26
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PART II
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Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters....................... 27
Item 6. Selected Financial Data......................................................................... 27
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.................................................................................... 27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...................................... 36
Item 8. Financial Statements and Supplementary Data..................................................... 37
Item 9. Changes in and disagreements with Accountants on Accounting and Financial
Disclosure.................................................................................... 48
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PART III
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Item 10. Directors and Executive Officers of the Registrant.............................................. 49
Item 11. Executive Compensation.......................................................................... 49
Item 12. Security Ownership of Certain Beneficial Owners and Management.................................. 49
Item 13. Certain Relationships and Related Transactions.................................................. 49
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PART IV
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Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................ 51
SIGNATURES................................................................................................. 52
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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 (as defined herein) have
advised the Trust that they believe that the expectations reflected in the
forward-looking statements contained herein are reasonable, no assurance can be
given that such expectations will prove to have been correct. Important factors
that could cause actual results to differ materially from expectations
("Cautionary Statements") are disclosed in this Form 10-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., Richard L.
Melton and Gary C. Evans 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, PennzEnergy Company ("PennzEnergy") (formerly named
Pennzoil Company) acquired certain oil and gas producing properties from
Chevron, including four of the Royalty Properties. The four Royalty Properties
acquired by PennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island
367 and Eugene Island 208. As a result of such acquisition, PennzEnergy replaced
Chevron as the Working Interest Owner of such properties on October 30, 1992.
PennzEnergy also assumed Chevron's obligations under the Conveyance with respect
to such properties.
On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco")
acquired two of the Royalty Properties from Chevron. The Royalty Properties
acquired by Texaco were West Cameron 643 and East Cameron 371/381. As a result
of such acquisition, Texaco replaced Chevron as the Working Interest Owner of
such properties on December 1, 1994. Texaco also assumed Chevron's obligations
under the Conveyance with respect to such properties.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced
PennzEnergy as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, and also assumed PennzEnergy's obligations
under the Conveyance with respect to such properties.
Effective January 1, 1998, Energy Resource Technology, Inc. ("Energy")
acquired the East Cameron 354 property from SONAT. As a result of such
acquisition, Energy replaced SONAT as the Working Interest Owner of the East
Cameron 354 property effective January 1, 1998, and also assumed SONAT's
obligations under the Conveyance with respect to such property. In October 1998,
Amerada Hess Corporation ("Amerada") acquired the East Cameron 354 property
from Energy effective January 1, 1998. As a result of such acquisition, Amerada
replaced Energy as the Working Interest Owner of the East Cameron 354 property
effective January 1, 1998, and also assumed Energy'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.
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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 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;
PennzEnergy with respect to East Cameron 354, Eugene Island 348, Eugene Island
367 and Eugene Island 208 for periods from October 30, 1992 until October 1,
1995, and with respect to Eugene Island 348 and Eugene Island 208 thereafter;
Texaco with respect to West Cameron 643 and East Cameron 371/381 for periods
beginning on or after December 1, 1994; SONAT with respect to East Cameron 354
for periods 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 Amerada
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. The Units are traded on the OTC Bulletin Board of
the National Association of Securities Dealers Automated Quotation System. The
Units may also be traded on pink sheets. From inception of the Trust to December
31, 1999, distributions to Unit holders totaled approximately $83,010,000, or
approximately $17.47 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
$22.7 million as of October 31, 1999. (See "Termination of the Trust" and Note
8 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: (1) December 31, 2030, (2) the election of
the Trust to dissolve the Partnership, (3) the termination of the Trust, (4) the
bankruptcy of the Managing General Partner of the Partnership, (5) the
dissolution of the Managing General Partner or its election to dissolve the
Partnership; however, the Managing General Partner has agreed not to dissolve or
to elect to dissolve the Partnership and shall be liable for all damages and
costs to the Trust if it breaks this agreement.
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
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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 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 (1) 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); (2) all applicable
taxes (including severance and ad valorem taxes) excluding income taxes; (3) all
operating charges directly associated with the Royalty Properties; (4) an
allowance for costs, computed on a current basis at a rate equal to the prime
rate of The Chase Manhattan Bank 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; (5) applicable charges for certain overhead expenses as
provided in the Conveyance; (6) the management fees and expense reimbursements
owing the Working Interest Owners; and (7) 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
Managing General Partner on behalf of the Partnership 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
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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 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,
PennzEnergy acquired certain oil and gas producing properties from Chevron,
including four of the Royalty Properties. The four Royalty Properties acquired
by PennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 and
Eugene Island 208. As a result of such acquisition, PennzEnergy replaced Chevron
as the Working Interest Owner of such properties and assumed Chevron's
obligations under the Conveyance with respect to such properties on October 30,
1992. On December 1, 1994, Texaco acquired two of the Royalty Properties from
Chevron. The Royalty Property acquired by Texaco is West Cameron 643 and East
Cameron 371/381. 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 PennzEnergy. As a result of such acquisitions,
SONAT and Amoco replaced PennzEnergy as the Working Interest Owners of the East
Cameron 354 and Eugene Island 367 properties, respectively, and also assumed
PennzEnergy'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. In October 1998, Amerada Hess Corporation ("Amerada") acquired
the East Cameron 354 property from Energy effective January 1, 1998. As a result
of such acquisition, Amerada replaced Energy as the Working Interest Owner of
the East Cameron 354 property effective January 1, 1998, and also assumed
Energy's obligations under the Conveyance with respect to such property.
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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, (1)
the substantial value and passive nature of the Trust assets, (2) the
restrictions on the power of the Trustees to incur liabilities on behalf of the
Trust and (3) 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 that 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 those 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 that 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, this 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 those distributions. Backup withholding will not normally apply
to distributions to a Unit holder, however, unless a 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 a 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. 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 the 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 the Unit was held by the Unit holder as a capital asset, either
long-term or short-term depending on the holding period of the Unit. This
capital gain or loss will be long-term if a Unit Holder's holding period for the
Units exceeded one year as of the date of sale or exchange. A long-term capital
gains rate of 20% applies to most capital assets sold with a holding period of
more than one year. Capital gain or loss will be short-term if the Unit has not
been held for more than one year at the time of disposition.
FOREIGN UNIT HOLDERS
In general, a Unit holder who is a nonresident alien individual or which is
a foreign corporation (each, a "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 that election that Unit holder
is entitled to claim all deductions with respect to that income, but he must
file a United States income tax return to claim those deductions. This election
once made is irrevocable (unless an applicable treaty allows the election to be
made annually). However, that 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 Taxpayers owning greater than five percent of
the outstanding Units (or 237,576 Units) are subject to United States income tax
on the gain on the disposition of their Units. Foreign Taxpayers owning five
percent or less of the outstanding Units are not subject to United States income
tax on the gain on the disposition of their Units.
7
<PAGE>
Federal income taxation of a Foreign Taxpayer is a highly complex matter
which may be affected by many other considerations. Therefore, each Taxpayer
holder 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 that 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 these 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 $22.7 million as of October 31, 1999, 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, 1999, it
is estimated that approximately 75% 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 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.
8
<PAGE>
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 (1) be distributed in kind ratably
to the Trust and the Managing General Partner or (2) 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, 1999
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>
East Cameron 354................................... 12-72 50.00 5,000 2 4 0 5
West Cameron 643................................... 12-72 50.00 5,000 3 17 0 14
Eugene Island 339.................................. 12-72 50.00 5,000 2 37 33 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 4 7 0 8
East Cameron 370(4)................................ 1-73 25.00 5,000 3 1 0 4
East Cameron 371................................... 1-73 25.00 5,000 7 2 0 4
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 0
Ship Shoal 183 N/2................................. 12-73 66.70 2,500 1 28 28 0
Ship Shoal 183 NW/4 of S/2......................... 4-77 50.00 625 0 1 1 0
Ship Shoal 183 NE/4 of SW/4
of S/2, SE/4..................................... 12-82 50.00 1,875 1 0 1 0
Eugene Island 208.................................. 8-73 100.00 1,250 0 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 0 1
South Timbalier 36................................. 3-74 .30 5,000 2 20 9 11
South Timbalier 37................................. 3-74 .30 5,000 13 34 33 2
--------- ----- ---- --- ---
78,747 55 206 105 104
========= ===== ==== === ===
</TABLE>
- ------------
(1) As of October 31, 1999, there were no wells in the process of drilling.
See "Operations" under Item 7 of this report for a discussion of
drilling activity during 1999.
(2) As of October 31, 1999, there were 80 producing completions.
(3) Multiple completions are counted as one well. South Timbalier 36 has 2
multiple completion wells and South Timbalier 37 has 12 multiple
completion wells. Ship Shoal 182/183 has 1 multiple completion well.
(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,
1999. 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 2 and 8 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,
1999, approximately 18,731 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 8 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 $11,200 in 1999
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, PennzEnergy, 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 $446,600 has been recovered from the Trust by
PennzEnergy as of the end of 1999, and the remainder will be subject to recovery
from the Trust in future periods, in accordance with the Conveyance. PennzEnergy
has advised the Trust that future Royalty income attributable to all of the
Royalty Properties owned by PennzEnergy 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 PennzEnergy, it is estimated that Royalty income
attributable to such properties will be retained by PennzEnergy for the
remaining life of the Trust. The Trust does not anticipate that retention of
such Royalty income by PennzEnergy will have a material effect on the Trust's
Royalty income as a whole.
10
<PAGE>
DEGOLYER AND MACNAUGHTON
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
LETTER REPORT
AS OF
OCTOBER 31, 1999
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
February 8, 2000
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,
1999, 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 Managing
Partner of the Trust Partnership is 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. The SONAT property was subsequently acquired by Amerada Hess
Corporation (Amerada Hess) effective January 1, 1998.
12
<PAGE>
DEGOLYER AND MACNAUGHTON
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, 1999. 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 of delivery, after reduction
for fuel usage, flare, and shrinkage resulting from field separations and
processing. 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
13
<PAGE>
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,
14
<PAGE>
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 interest in three of the productive properties.
Amerada Hess and Amoco own an interest in one property each, but only the
Amerada Hess property is productive. Chevron owns an interest in the remaining
10 properties.
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, Amerada Hess,
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>
<S> <C> <C>
Trust Partnership Interest
Trust Partnership Interest net reserves = future net revenue x Combined net
------------------ reserves
Combined future gross revenue
</TABLE>
This formula was applied separately to the Pennzoil, Texaco, Amerada Hess, 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
15
<PAGE>
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, Amerada Hess, 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 1999 were used in estimating gross ultimate recovery. Gross production
estimated through October 31, 1999, 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 1999.
16
<PAGE>
Net proved reserves attributable to the Trust Partnership Interest, as
of October 31, 1999, are estimated as follows:
OIL AND NATURAL
CONDENSATE GAS
(BBL) (MCF)
---------- ---------
Proved Developed and Undeveloped Reserves
Reserves as of October 31, 1998 ................. 652,483 3,718,432
Revisions of Previous Estimates ................. 200,224 786,426
Improved Recovery ............................... 0 0
Purchases of Minerals in Place .................. 0 0
Extensions, Discoveries, and Other Additions .... 2,841 42,184
Production ...................................... (242,496) (1,197,518)
Sales of Minerals in Place ...................... 0 0
Reserves as of October 31, 1999 ................. 613,052 3,349,524
Proved Developed Reserves
Reserves as of October 31, 1998 ................. 652,356 3,710,098
Reserves as of October 31, 1999 ................. 612,610 3,338,142
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 2000. 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 4.62 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, Amerada Hess, and
Amoco). Interest was charged monthly on the net profits deficit balances (costs
not recovered currently) at the rate of 4.62 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
17
<PAGE>
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, 1999. 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, 1999. The
assumptions used for estimating future prices and costs are as follows:
OIL AND CONDENSATE PRICES
Oil and condensate prices applicable in October 1999 were used as
initial prices with no increases based on inflation. The initial oil
and condensate prices were furnished by Chevron.
NATURAL GAS PRICES
Initial gas prices furnished by Chevron were prices in effect on
October 31, 1999, 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 1999 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.
18
<PAGE>
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, 1999, is as follows:
<TABLE>
<CAPTION>
AMERADA
CHEVRON PENNZOIL TEXACO HESS AMOCO
PROPERTIES PROPERTIES PROPERTIES PROPERTIES PROPERTIES TOTAL
---------- ---------- ---------- ------------ ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
COMBINED INTEREST
Future Gross Revenue ($) .................. 77,307,780 1,089,954 19,461,274 713,184 0 98,572,192
Operating Costs ($) ....................... (8,285,841) (206,766) (4,573,030) (331,084) 0 (13,396,721)
Capital Costs ($)(1) ...................... (10,201,464) (191,750) (5,587,085) (278,410) 0 (16,258,709)
Future Net Revenue ($) .................... 58,820,475 691,438 9,301,159 103,690 0 68,916,762
Cost Escrow as of 10-31-99 ($) ............ 13,362,400 235,140 8,216,386 403,036 0 22,216,962
Interest Credit on Accrued Balance ($) .... 2,294,672 57,055 1,152,406 34,853 0 3,538,986
Interest on Deficit ($) ................... 0 0 0 0 0 0
Overhead ($) .............................. (2,942,462) (46,266) (923,079) (40,704) 0 (3,952,511)
Revenue Subject to Net Profits Interest ($) 71,535,085 937,367 17,746,872 500,875 0 90,720,199
TRUST PARTNERSHIP INTEREST
Future Net Revenue ($)(2) ................. 17,883,721 234,321 4,436,686 125,210 0 22,679,938
Present Worth at 10 Percent ($)(2) ........ 14,593,893 193,357 3,758,778 113,557 0 18,659,585
</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.
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
19
<PAGE>
currently available, but such estimates are also subject to the uncertainties
inherent in the application of judgmental factors in interpreting such
information.
Submitted,
/s/ DeGOLYER and MacNAUGHTON
DeGolyer and MacNaughton
-------------------------
| |
| STATE OF TEXAS |
| THOMAS A. SCHOB |
| 52722 |
| REGISTERED |
| PROFESSIONAL ENGINEER | /s/ THOMAS A. SCHOB, P.E.
| | Thomas A. Schob, P.E.
------------------------- Vice President
DeGolyer and MacNaughton
20
<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 8 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 $372,500 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, 1999 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 generally increased in 1999 and early
2000. Crude oil prices increased in 1999 and early 2000.
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 1999, gas sales by the Working Interest Owners under a contract with
Texaco Natural Gas, Inc. ("TNG") and Dynegy Inc. ("Dynegy") accounted for
46% and 47%, respectively, of total gas revenues from the Royalty Properties.
21
<PAGE>
Effective August 31, 1996, Chevron's Natural Gas Business Unit and Warren
Petroleum Company merged with Dynegy (formerly named 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 Dynegy 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 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 63% of the
revenues from gas sales from the Royalty Properties in 1999. The average price
received for natural gas from all of the Working Interest Owner's purchasers on
West Cameron 643 during 1999 was $2.33 per Mcf and the price received for
February 2000 was $2.38 per Mcf. The gas from West Cameron 643 is currently
committed to Texaco Natural Gas Inc. ("TNGI"). TNGI is a wholly owned affiliate
of Texaco Exploration and Production Inc. ("TEPI"). TNGI purchases natural gas
from TEPI and resells such gas to a variety of third-party customers at a
variety of downstream delivery points. The prices that TNGI pays TEPI for the
gas production is based on the actual sale prices that TNGI receives from its
third-party customers less the actual transportation cost, if any, that TNGI
pays to a transporting pipeline. TEPI's proceeds are based on 100% of the actual
resale price of the gas, less actual transportation.
EAST CAMERON 371/381. East Cameron 371/381 contributed approximately (15)%
of the revenues from gas sales from the Royalty Properties in 1999. The average
price received for natural gas from all of the Working Interest Owner's
purchasers on East Cameron 371/381 during 1999 was $2.07 per Mcf and the price
received for February 2000 was $2.26 per Mcf. The gas from East Cameron 371/381
is currently committed to TNGI on terms similar to gas committed to West Cameron
643
SHIP SHOAL 182/183. Ship Shoal 182/183 contributed approximately 33% of
the revenues from gas sales from the Royalty Properties in 1999. The average
price received for natural gas from all of the Working Interest Owner's
purchasers on Ship Shoal 182/183 during 1999 was $2.19 per Mcf and the price
received for February 2000 was $2.50 per Mcf. The gas from Ship Shoal 182/183 is
committed to Dynegy at a calculated price based on the monthly Inside FERC
Tennessee-Louisiana Zone 1 Index.
EUGENE ISLAND 339. Eugene Island 339 contributed approximately 9% of the
revenues from gas sales from the Royalty Properties in 1999. The average price
received for natural gas from all of the Working Interest Owner's purchasers on
Eugene Island 339 during 1999 was $2.21 per Mcf and the price received for
February 2000 was $2.31 per Mcf. The gas from Eugene Island 339 is committed to
Dynegy at a calculated price based on the monthly Inside FERC
Tennessee-Louisiana Zone 1 Index.
OIL MARKETING
Crude oil purchases by Texaco, Inc. and by the Supply and Distribution
Department of Chevron accounted for approximately 9% and 91%, respectively, of
total crude oil revenues from the Royalty Properties during 1999.
22
<PAGE>
Under TEPI's tendering procedure, Equiva Trading Company (Texaco's crude
oil marketing joint venture) purchases crude oil based on the prices TEPI
receives from third parties under a competitive bidding procedure. Average
monthly prices for fiscal 1999 ranged from $11.1284 per barrel to $26.4543 per
barrel. The average crude oil price under this arrangement for January 2000
production was approximately $26.23 per barrel.
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 1999
ranged from $9.34 per barrel to $21.72 per barrel. The average price of crude
oil sold under this arrangement for February 2000 was approximately $28.68 per
barrel.
23
<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.
FERC REGULATION
In recent years, the FERC has required interstate pipeline companies to
"unbundle" their services. To the extent a pipeline company or its sales
affiliate makes gas sales as a merchant, it does so pursuant to private
contracts in direct competition with all other sellers, such as the Working
Interest Owners. In recent years, the FERC also has pursued a number of other
policy initiatives which could significantly affect the marketing of natural
gas. Several of these initiatives are intended to enhance competition in natural
gas markets, although some, such as "spin downs of gathering assets," may have
the adverse effect of increasing the cost of doing business on some in the
industry. In 1996, the FERC issued a Statement of Policy regarding its
jurisdiction under the NGA and OCSLA over new natural gas facilities and
services on the OCS. Generally, the FERC retained its existing tests for
determining the jurisdictional status of offshore facilities, but eased the
application of its jurisdiction over facilities in water depths of 200 meters or
more. On February 9, 2000, the FERC issued Order No. 637, which permits, and in
some cases requires, interstate natural gas pipelines to make certain changes to
the nature of interstate transportation services. In addition to the changes
implemented through Order No. 637, the FERC has stated that it will institute a
review of its regulatory model in light of the changes in the natural gas
industry. Requests for rehearing of Order No. 637 are pending before the FERC.
Once the FERC has addressed the rehearing requests, the order may be subject to
judicial review. As to all of these recent FERC initiatives, the Working
Interest Owners have advised the Trust that the ongoing or, in some instances,
preliminary evolving nature of these regulatory initiatives makes it impossible
at this time to predict their ultimate impact on the prices, markets or terms of
sale of natural gas related to the Trust.
STATE REGULATION
State regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, non-discriminatory take requirements.
Some states have implemented more stringent legislation in recent years to
regulate gathering rates charged by gas gathering companies, but to date the
effect on the Working Interests Owners in connection with the Trust has been
minimal.
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
24
<PAGE>
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. In 1998, the
Minerals Management Service adopted regulations for establishing the amount of
OSFR required for particular facilities. The amount of OSFR increases 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 is required; for worst-case spills of over 35,000 barrels, $70 million
is required; for worst-case spills of over 70,000 barrels, $105 million is
required; and for worst-case spills of over 105,000 barrels, $150 million is
required. In addition, all OSFR below $150 million remains subject to upward
regulatory adjustment if warranted by the particular operational, environmental,
human health or other risks involved with a facility. The Working Interest
Owners are currently maintaining their required OSFR. 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, 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.
The Working Interest Owners have advised the Trust that these costs have not had
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 capital expenditures 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.
25
<PAGE>
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 "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 1999.
26
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Trust Units are traded on the OTC Bulletin Board. The Trust Units may
also be traded on pink sheets. At March 17, 2000, the 4,751,510 Units
outstanding were held by 1,848 Unit holders of record. The high and low sales
price as reported by the OTC Bulletin Board, and distributions for each quarter
for the years ended December 31, 1999 and 1998, were as follows:
QUARTER HIGH LOW DISTRIBUTION
------- ---- --- ------------
1999:
Fourth.......................... $ 4 $3 7/16 $.436046
Third........................... 3 7/8 3 7/16 .127953
Second.......................... 4 1/4 3 3/8 .000000
First........................... 4 3/8 3 9/16 .011700
1998:
Fourth.......................... $ 4 5/8 $3 1/4 $.360208
Third........................... 5 1/4 4 1/2 .170549
Second.......................... 5 5/8 5 .213754
First........................... 5 7/16 4 1/2 .413421
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.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------
1999 1998 1997 1996 1995
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Royalty income....................... $ 2,953,377 $ 5,773,114 $ 7,003,259 $ 785,708 $ 1,383,458
Distributable income................. $ 2,735,446 $ 5,501,938 $ 6,058,057 $ 590,417 $ 614,836
Distributions per Unit............... $ .575699 $ 1.157932 $ 1.274973 $ .124258 $ .129396
Total assets......................... $ 3,823,891 $ 3,520,190 $ 4,128,590 $ 1,818,212 $ 2,333,224
</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 8 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 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
27
<PAGE>
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. In the first quarter of 1998, the Trust determined
that the Trust's cash reserve was currently sufficient to provide for future
administrative expenses in connection with the winding up of the Trust. The
Trust determined that a cash reserve equal to three times the average expenses
of the Trust during each of the past three years was sufficient at this time to
provide for future administrative expenses in connection with the winding up of
the Trust. This reserve amount for 1998 was $1,366,035. The excess amount of
$106,654 was distributed to Unit holders in the first quarter of 1998, and no
deposits were made to the Trust's cash reserve account during 1998. The reserve
amount at December 31, 1999 was $1,384,243. A deposit of $18,208 was made to the
Trust's cash reserve account in the first quarter of 1999. During the second
quarter of 1999, the Trust used $25,258 from the Trust's cash reserve account to
pay the Trust's general and administrative expenses, when insufficient Royalty
income was received by the Trust. This $25,258 was redeposited to the Trust's
cash reserve account during the third quarter of 1999.
OPERATIONS
YEARS 1999 AND 1998
During the first quarter of 1999, the Working Interest Owner of East
Cameron 371/381 informed the Trust that Texaco overpaid royalties to the Trust
in the third and fourth quarters of 1998 in an amount totaling $1,090,367.
Texaco recouped $404,190 of the overpayment from production in the first six
months of 1999 and was to recoup additional royalties of $686,177 in future
periods through future production on this property and West Cameron 643, which
properties are operated by Texaco. Texaco informed the Trust in the third
quarter of 1999 that it was required to make additional adjustments to reported
financial information on these properties. These adjustments resulted from
Texaco's audit of these Trust properties. This audit was made by Texaco at the
request of the Trustees of the Trust. Adjustments arising from this audit
included previous capital expenditures and exploratory costs not charged to the
Trust that were offset by revenues from plant liquids and oil, as well as
revenues attributable to differences in pricing formulas, that should have been
paid to the Trust. After netting these findings, Texaco has informed the Trust
that the loss carryforward projected in the first two quarters of 1999 should be
adjusted and eliminated, and that Texaco owed the Trust approximately $80,000.
The following summary presents 1998 and 1999 activity inclusive of these
adjustments.
Royalty income decreased approximately 49% from $5,773,114 in 1998 to
$2,953,377 in 1999 primarily due to a significant decrease in gas revenues as
discussed below. This decrease in gas revenues was partially offset by the
significant decrease in capital expenditures in 1999 as discussed below.
For 1999, the Trust had an undistributed net loss of approximately $783,489
compared to undistributed net income of approximately $41,657 in 1998.
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 1998 was applied to a loss carryforward that
resulted from 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 decreased approximately 50% from $21,917,044 in 1998 to
$10,952,595 in 1999, due primarily to a 53% decrease in gas volumes from
10,005,749 Mcf in 1998 to 4,696,022 Mcf in 1999. The decrease in volumes was
primarily attributable to volume and royalty overpayments made by the Working
28
<PAGE>
Interest Owner of the East Cameron 371/381 property to the Trust during the
third and fourth quarters of 1998. The decrease in volumes was slightly offset
by a 5% increase in the average price received for natural gas from $2.22 per
Mcf in 1998 to $2.32 per Mcf in 1999.
Chevron has advised the Trust that as of October 31, 1999 approximately
18,731 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 8 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 $11,200 in 1999 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, PennzEnergy, 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 $446,600 has been recovered from the Trust,
including $78,000 and $42,300 during 1999 and 1998, 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 PennzEnergy 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 PennzEnergy, it is estimated that Royalty income
attributable to such properties will be retained by PennzEnergy for the
remaining life of the Trust. The Trust does not anticipate that retention of
such Royalty income by PennzEnergy will have a material effect on the Trust's
Royalty income as a whole.
CRUDE OIL AND CONDENSATE
Crude oil and condensate revenues decreased approximately 15% from
$18,060,937 in 1998 to $15,413,693 in 1999, due primarily to a 25% decrease in
crude oil and condensate volumes from 1,301,651 barrels in 1998 to 969,984
barrels in 1999. The decrease in volumes was primarily attributable to the
adjustments referred to above on the East Cameron 371/381 property and West
Cameron 643 property. This decrease in volumes was slightly offset by a 14%
increase in the average price received from $13.88 per barrel in 1998 to $15.89
per barrel in 1999.
OPERATING AND CAPITAL EXPENDITURES
Operating expenses increased approximately 1% from $4,342,765 in 1998 to
$4,369,885 in 1999.
Capital expenditures decreased approximately 60% from $16,590,617 in 1998
to $6,633,800 in 1999 due primarily to the costs associated with drilling the
B-7, B-9 and B-12 wells in the first quarter of 1998 and the B-16 well in the
second quarter of 1998 on the Eugene Island 339 property.
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 $202,900 in 1999, 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
29
<PAGE>
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 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 2000, there was a net deposit of funds into the
Special Cost Escrow Account of approximately $265,000. The deposit was primarily
a result of an increase in the current estimate of projected capital
expenditures of the Royalty Properties.
In 1999, the Working Interest Owners deposited a net amount of
approximately $1,587,400 into the Special Cost Escrow Account. The deposit was
primarily a result of an increase in the estimate of projected capital
expenditures on the Royalty Properties. In addition there was a deposit
adjustment of approximately $576,500 made in the second quarter of 1999 due to a
release not being made in the fourth quarter of 1997. As of December 31, 1999,
approximately $5,493,000 remained in the Special Cost Escrow Account.
In 1998, the Working Interest Owners released a net amount of approximately
$1,292,800 from the Special Cost Escrow Account. The release was made primarily
due to a decrease in the estimate of projected capital expenditures, production
costs and abandonment costs 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.
SUMMARY BY PROPERTY
Listed below is a summary of 1999 operations as compared to 1998 of the
four principal Royalty Properties based on gross revenues generated.
EUGENE ISLAND 339
Eugene Island 339 crude oil revenues increased from $4,663,521 in 1998 to
$5,053,716 in 1999 primarily due to an increase in the average crude oil price
from $12.39 per barrel in 1998 to $13.96 per barrel in 1999. This increase in
price was partially offset by a decrease in volumes from 376,500 barrels in 1998
to 362,018 barrels in 1999. Gas revenues decreased from $1,275,998 in 1998 to
$976,051 in 1999 primarily due to a decrease in gas volumes from 602,519 Mcf in
1998 to 487,938 Mcf for the same period in 1998. The decrease in gas volumes was
due primarily to continued natural production decline on this property. In
addition, there was a decrease in the average price received for natural gas
from $2.27 per Mcf in 1998 to $2.21 per Mcf in 1999. Operating expenses
increased from $718,706 in 1998 to $1,480,059 in 1999 due primarily to an
adjustment to properly reflect costs in the first quarter of 1998. Capital
expenditures decreased $9,225,296 in 1999 in comparison to 1998 due primarily to
drilling activity on the B-7, B-9 and B-12 wells in the first quarter of 1998.
As discussed under "Description of the Royalty Properties -- Reserves,"
the Working Interest Owner has advised the Trust that as of October 31, 1999
there was an overtake imbalance position of approximately 18,731 Mcf (4,683 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 plans to drill a
delineation well in mid-2000 at an aggregate cost of approximately $2,769,000
($692,250 net to the Trust).
30
<PAGE>
SHIP SHOAL 182/183
Ship Shoal 182/183 crude oil revenues decreased from $12,785,064 in 1998 to
$8,751,680 in 1999 primarily due to a decrease in crude oil production from
881,477 barrels in 1998 to 570,487 barrels in 1999. The decrease in crude oil
production was due primarily to continued natural production decline on these
properties and due to a compressor being shut down for 12 days in April 1999 due
to mechanical problems experienced in the production facilities. This decrease
in volumes were partially offset by an increase in the average crude oil price
from $14.50 per barrel in 1998 to $15.34 per barrel for the same period in 1999.
Gas revenues decreased from $5,046,157 in 1998 to $3,667,882 in 1999 due to a
decrease in the average natural gas sales price from $2.24 per Mcf in 1998 to
$2.19 per Mcf in 1999. In addition, there was a decrease in gas volumes from
2,327,228 Mcf in 1998 to 1,740,431 Mcf in 1999. This decrease in gas volumes was
due primarily to the E-2 well being shut-in in the third quarter of 1999, a
production decline on the E-10 well in the fourth quarter of 1999 and the F-2
well no longer producing as of the fourth quarter of 1999. Operating expenses
decreased from $1,564,303 in 1998 to $1,561,850 in 1999. Capital expenditures
decreased from $1,575,518 in 1998 to $1,570,205 in 1999.
The Working Interest Owner has advised the Trust that approximately 99,934
Mcf have been overtaken by the Working Interest Owner from this property. The
Trust's share of this overtake position is approximately 24,983 Mcf.
Accordingly, gas revenues from this property may be reduced in future periods
while underproduced parties recover their share of the gas imbalance.
WEST CAMERON 643
West Cameron 643 gas revenues decreased from $8,398,405 in 1998 to
$6,846,390 in 1999 due primarily to a decrease in gas volumes from 3,665,784 Mcf
in 1998 to 2,942,979 Mcf in 1999. The decrease in gas volumes was due primarily
to lower production in 1999 on the A-2, A-9, B-8 and B-9 wells drilled in 1996,
the B-9 well watering out in the fourth quarter of 1998 and the continued
natural production decline. This decrease in volumes was slightly offset by an
increase in the average price received for natural gas from $2.29 per Mcf in
1998 to $2.33 per Mcf in 1999. Operating expenses decreased from $1,460,966 in
1998 to $998,964 in 1999, due primarily to workovers performed in 1998 on the
A-6 and A-17 wells. Capital expenditures increased from $1,215,381 in 1998 to
$1,312,924 in 1999.
EAST CAMERON 371/381
East Cameron 371/381 started production in May 1998. Gas revenues on this
property decreased from $5,696,741 in 1998 to ($1,688,792) in 1999 due primarily
to a decrease in gas volumes from 2,761,549 Mcf in 1998 to (1,010,290) Mcf in
1999. In 1998, gas revenues and volumes included overpaid revenues and volumes
made by the Working Interest Owner of $4,272,556 and 2,071,162 Mcf, respectively
(a net adjustment of $1,090,367 to the Trust). Therefore, an adjustment for this
1998 overpayment was made in the first quarter of 1999. The Working Interest
Owner of East Cameron 371/381 recouped $404,190 of the overpayment from
production in the first six months of 1999 and was to recoup additional
royalties of $686,177 in future periods through future production on this
property and West Cameron 643, which properties are operated by this Working
Interest Owner. In addition there were upward adjustments of $69,240 for gas
revenues made in the third quarter of 1999 as discussed above. Crude oil
revenues increased from $299,008 in 1998 to $1,080,222 in 1999 due primarily to
an upward adjustment of $734,161 made in the third quarter of 1999 as discussed
above. Capital expenditures decreased from $3,916,828 to $3,316,826 in 1999.
Operating expenses decreased from $337,608 in 1998 to $107,186 in 1999, due
primarily to a $261,718 downward adjustment made in the third quarter as
discussed above.
YEARS 1998 AND 1997
During the first quarter of 1999, the Working Interest Owner of East
Cameron 371/381 informed the Trust that the Working Interest Owner overpaid East
Cameron 371/381 royalties, related primarily to natural gas production, to the
Trust in the third and fourth quarters of 1998. The total gas revenue and volume
reported to the Trust was $5,696,741 ($1,424,185 net to the Trust) and 2,761,549
Mcf (690,387 Mcf net to the Trust), respectively. The amount that should have
been reported to the Trust for gas revenue and
31
<PAGE>
volume was $1,424,185 ($356,046, net to the Trust) and 690,387 Mcf (172,597 Mcf
net to the Trust), respectively. As a result of these miscalculations and other
minor adjustments, the Working Interest Owner overpaid the Trust royalties
totaling $1,090,367. Due to the overpayments, the Working Interest Owner of East
Cameron 371/381 will recoup the overpayment of royalties through future
production on East Cameron 371/381 and West Cameron 643, which properties are
operated by this Working Interest Owner.
Royalty income decreased approximately 18% from $7,003,259 in 1997 to
$5,773,114 in 1998 primarily due to a significant decrease in crude oil and
condensate revenues and a significant increase in capital expenditures in 1998
on Ship Shoal 182/183 property as discussed below. This decrease was partially
offset by the $1,090,367 in royalty overpayments on East Cameron 371/381
property as discussed above.
For 1998, the Trust had an undistributed net income of approximately
$41,657 compared to undistributed net income of approximately $952,683 in 1997.
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 1998 was applied to a loss carryforward that
resulted from 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 17% from $18,680,941 in 1997 to
$21,917,044 in 1998, due primarily to a 43% increase in gas volumes from
6,990,809 Mcf in 1997 to 10,005,749 Mcf in 1998. The increase in volumes was
primarily attributable to production beginning in May 1998 on the East Cameron
371/381 property and the related volume and royalty overpayments made by the
property's Working Interest Owner to the Trust during the third and fourth
quarters of 1998. The increase in volumes was partially offset by a 16% decrease
in the average price received for natural gas from $2.69 per Mcf in 1997 to
$2.22 per Mcf in 1998.
Chevron has advised the Trust that as of October 31, 1998 approximately
74,730 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 $33,300 in 1998 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, PennzEnergy, 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 $363,400 has been recovered from the Trust,
including $42,300 and $166,100 during 1998 and 1997, 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 PennzEnergy 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 PennzEnergy, it is estimated that Royalty income
attributable to such properties will be retained by PennzEnergy for the
remaining life of the Trust. The Trust does not anticipate that retention of
such Royalty income by PennzEnergy will have a material effect on the Trust's
Royalty income as a whole.
32
<PAGE>
CRUDE OIL AND CONDENSATE
Crude oil and condensate revenues decreased approximately 40% from
$30,018,655 in 1997 to $18,060,937 in 1998 due primarily to a 31% decrease in
the average price received from $20.06 per barrel in 1997 to $13.88 per barrel
in 1998. In addition, there was a 13% decrease in crude oil and condensate
volumes from 1,496,617 barrels in 1997 to 1,301,651 barrels in 1998. This
decrease in volumes was primarily attributable to decreased production from the
B-11, B-12 and B-13 wells in the Ship Shoal 182/183 property in 1998.
OPERATING AND CAPITAL EXPENDITURES
Operating expenses decreased approximately 30% from $6,243,109 in 1997 to
$4,342,765 in 1998 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 increased approximately 125% from $7,379,553 in 1997
to $16,590,617 in 1998 due primarily to the costs associated with drilling the
B-7, B-9 and B-12 wells in the first quarter of 1998 and the B-16 well in the
second quarter of 1998 on the Eugene Island 339 property.
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 $225,000 in 1998, 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 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 1999, there was a deposit of funds into the Special
Cost Escrow Account of approximately $461,000. The deposit was primarily a
result of an increase in the current estimate of projected capital expenditures
of the Royalty Properties.
In 1998, the Working Interest Owners released a net amount of approximately
$1,292,800 from the Special Cost Escrow Account. The release was made primarily
due to a decrease in the estimate of projected capital expenditures, production
costs and abandonment costs of the Royalty Properties. As of December 31, 1998,
approximately $3,329,000 remained in the Special Cost Escrow Account.
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.
33
<PAGE>
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 1998 operations as compared to 1997 of the
four principal Royalty Properties based on gross revenues generated.
EUGENE ISLAND 339
Eugene Island 339 crude oil revenues decreased from $5,401,845 in 1997 to
$4,663,521 in 1998 primarily due to a decrease in the average crude oil price
from $18.46 per barrel in 1997 to $12.39 per barrel in 1998. This decrease in
price was partially offset by an increase in volumes from 292,657 barrels in
1997 to 376,500 barrels in 1998. The increase in volumes was primarily
attributable to successful workovers on the B-4 and B-12 wells in the third
quarter of 1998. Gas revenues increased from $957,846 in 1997 to $1,275,998 in
1998 primarily due to an increase in gas volumes from 351,775 Mcf in 1997 to
602,519 Mcf for the same period in 1998. The increase in gas volumes was due
primarily to a well being shut down during the first and second quarter of 1997
for upgrading the facility and compressor repair. The increase in gas volumes
was partially offset by a decrease in the average price received for natural gas
from $2.80 per Mcf in 1997 to $2.27 per Mcf in 1998. Operating expenses
decreased from $1,987,731 in 1997 to $718,706 in 1998 due primarily to service
facility charges in the second quarter of 1997. Capital expenditures increased
$9,523,332 in 1998 in comparison to 1997 due primarily to drilling activity on
the B-7, B-9 and B-12 wells in the first quarter of 1998.
As discussed under "Description of the Royalty Properties -- Reserves,"
the Working Interest Owner has advised the Trust that as of October 31, 1998
there was an overtake imbalance position of approximately 74,731 Mcf (18,683 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 they plan to drill
the B-5. B-12 and B-16 sidetrack wells in early 1999 at an aggregate cost of
approximately $2,072,000 ($518,000 net to the Trust).
SHIP SHOAL 182/183
Ship Shoal 182/183 crude oil revenues decreased from $24,329,563 in 1997 to
$12,785,064 in 1998 primarily due to a decrease in crude oil production from
1,189,636 barrels in 1997 to 881,477 barrels in 1998. The decrease in crude oil
production was due primarily to the lower production in 1998 on the B-11, B-12
and B-13 wells that were drilled in 1996 and the B-15 well that was drilled in
the third quarter of 1997. In addition, there was a decrease in the average
crude oil price from $20.45 per barrel in 1997 to $14.50 per barrel in 1998. Gas
revenues decreased from $5,276,887 in 1997 to $5,046,157 in 1998 due to a
decrease in the average natural gas sales price from $2.64 per Mcf in 1997 to
$2.24 per Mcf in 1998. The decrease in price was offset by an increase in gas
volumes from 2,046,588 Mcf in 1997 to 2,327,228 Mcf in 1998. The increase in gas
volumes was primarily due to the E-10 well beginning production in June 1998.
Operating expenses decreased from $1,998,890 in 1997 to $1,564,303 in 1998
primarily due to a reduction in drilling activity in 1998 and the workover on
the E-9 well in the first quarter of 1997. Capital expenditures decreased from
$4,817,257 in 1997 to $1,575,518 in 1998 primarily due to capital expenditures
recognized in 1997 from the drilling and completion of the B-11, B-12, and B-13
wells in 1996.
The Working Interest Owner has advised the Trust that approximately 25,114
Mcf have been overtaken by the Working Interest Owner from this property. The
Trust's share of this overtake position is approximately 6,279 Mcf. Accordingly,
gas revenues from this property may be reduced in future periods while
underproduced parties recover their share of the gas imbalance.
34
<PAGE>
The Working Interest Owner has advised the Trust that it plans to drill a
delineation well and sidetrack a well on this property in 1999 at an estimated
cost of approximately $5.4 million ($1.35 million net to the Trust).
WEST CAMERON 643
West Cameron 643 gas revenues decreased from $11,121,313 in 1997 to
$8,398,405 in 1998 due primarily to a decrease in the average price received for
natural gas from $2.72 per Mcf in 1997 to $2.29 per Mcf in 1998. In addition,
there has been a decrease in gas volumes from 4,093,126 Mcf in 1997 to 3,665,784
Mcf in 1998. The decrease in gas volumes was due primarily to lower production
in 1998 on the A-2, A-9, B-8 and B-9 wells drilled in 1996 and the B-9 well
watering out in the fourth quarter of 1998. Operating expenses decreased from
$1,775,710 in 1997 to $1,460,966 in 1998, due primarily to platform repairs in
the fourth quarter 1997. Capital expenditures increased from $379,637 in 1997,
to $1,215,381 in 1998 due primarily to increased rig activity due to the
sidetrack of the A-10 and A-14 wells in the second quarter of 1998 and the A-17
well workover in the second quarter of 1998.
EAST CAMERON 371/381
East Cameron 371/381 started production in May 1998. Gas revenues on this
property were $5,696,741 in 1998. Gas volumes were 2,761,549 Mcf and the average
price received for natural gas was $2.06 per Mcf in 1998. The 1998 gas revenues
and volumes include overpaid revenues and volumes made by the Working Interest
Owner of $4,272,556 and 2,071,162 Mcf, respectively. Capital expenditures were
$3,916,828 in 1998 due primarily to increased rig activity to bring the three
wells on production. The Working Interest Owner has advised the Trust that the
third well began production in late August 1998, the A-4 well was a dry hole and
they began drilling the A-5 well in November 1998. Operating expenses were
$337,608 in 1998.
35
<PAGE>
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)
----------------------------------------------
1999 1998(3) 1997
-------------- -------------- --------------
<S> <C> <C> <C>
Crude oil and condensate (bbls)......................... 969,984 1,301,651 1,496,617
Natural gas and gas products (Mcf)...................... 4,696,022 10,005,749 6,990,809
Crude oil and condensate average price, per bbl......... $ 15.89 $ 13.88 $ 20.06
Natural gas average price, per Mcf (excluding gas
products)............................................. $ 2.32 $ 2.22 $ 2.69
Crude oil and condensate revenues....................... $ 15,413,693 $ 18,060,937 $ 30,018,655
Natural gas and gas products revenues................... 10,952,595 21,917,044 18,680,941
Production expenses..................................... (4,702,240) (5,297,247) (7,275,354)
Capital expenditures.................................... (6,633,800) (16,590,617) (7,379,553)
Undistributed net loss (income)(2)...................... 3,133,956 (166,626) (3,810,733)
(Provision for) Refund of escrowed special costs........ (6,349,516) 5,171,273 (2,218,120)
-------------- -------------- --------------
NET PROCEEDS............................................ $ 11,814,688 $ 23,094,764 $ 28,015,836
Royalty interest........................................ x25% x25% x25%
-------------- -------------- --------------
Partnership share....................................... 2,953,672 5,773,691 7,003,959
Trust interest.......................................... x99.99% x99.99% x99.99%
-------------- -------------- --------------
Trust share............................................. $ 2,953,377 $ 5,773,114 $ 7,003,259
============== ============== ==============
</TABLE>
- ------------
(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, 1999, the loss
carryforward was $1,197,240 ($299,310 net to the Trust).
(3) During the first quarter of 1999, the Working Interest Owner of East
Cameron 371/381 informed the Trust that the Working Interest Owner
overpaid East Cameron 371/381 royalties, related primarily to natural gas
production, to the Trust in the third and fourth quarters of 1998. The
total gas revenue and volume reported to the Trust was $5,696,741
($1,424,185 net to the Trust) and 2,761,549 Mcf (690,387 Mcf net to the
Trust), respectively. The amount that should have been reported to the
Trust for gas revenue and volume was $1,424,185 ($356,046 net to the
Trust) and 690,387 Mcf (172,597 Mcf net to the Trust), respectively. As a
result of these miscalculations and other minor adjustments, the Working
Interest Owner overpaid the Trust royalties totaling $1,090,367. Due to
the overpayments, the Working Interest Owner of East Cameron 371/381 will
recoup the overpayment of royalties through future production on East
Cameron 371/381 and West Cameron 643, which properties are operated by
this Working Interest Owner.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Reference is made to Item 1 of this Form 10-K.
36
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
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, 1999, and the related
statements of distributable income and changes in trust corpus for the year
ended December 31, 1999. These financial statements are the responsibility of
the Trustees. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit 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 the
Trustees, as well as evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for our opinion.
As described in Note 3 to the financial statements, these financial
statements were prepared on a comprehensive basis of accounting other than
generally accepted accounting principles.
In our opinion, such financial statements present fairly, in all material
respects, the assets, liabilities and trust corpus of TEL Offshore Trust as of
December 31, 1999, and its distributable income and changes in trust corpus for
the year ended December 31, 1999, on the comprehensive basis of accounting
described in Note 3.
DELOITTE & TOUCHE LLP
Houston, Texas
March 15, 2000
37
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Trustees and Unit Holders of TEL Offshore Trust:
We have audited the accompanying statement of assets, liabilities and trust
corpus of TEL Offshore Trust as of December 31, 1998 and the related statements
of distributable income and changes in trust corpus for the years ended December
31, 1998 and 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 the
Trustees, 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, 1998, and its distributable income and changes
in trust corpus for each of the years ended December 31, 1998 and 1997, on the
comprehensive basis of accounting described in Note 3.
ARTHUR ANDERSEN LLP
Houston, Texas
March 30, 1999
38
<PAGE>
TEL OFFSHORE TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1999 1998
<S> <C> <C>
------------ ------------
ASSETS
Cash and cash equivalents......................................................... $ 3,456,123 $ 3,077,569
Net overriding royalty interest in oil and gas properties, net of accumulated
amortization of $27,899,887 and $27,825,034 at December 31, 1999 and 1998,
respectively.................................................................... 367,768 442,621
------------ ------------
Total assets...................................................................... $ 3,823,891 $ 3,520,190
============ ============
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders.............................................. $ 2,071,880 $ 1,711,534
Reserve for future Trust expenses................................................. 1,384,243 1,366,035
Commitments and contingencies
Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding at
December 31, 1999 and 1998)..................................................... 367,768 442,621
------------ ------------
Total liabilities and trust corpus................................................ $ 3,823,891 $ 3,520,190
============ ============
</TABLE>
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
1999 1998 1997
<S> <C> <C> <C>
------------ ------------ ------------
Royalty income.................................................. $ 2,953,377 $ 5,773,114 $ 7,003,259
Interest income................................................. 62,876 67,377 54,798
------------ ------------ ------------
3,016,253 5,840,491 7,058,057
General and administrative expenses............................. (262,599) (445,207) (406,934)
(Increase) Decrease in reserve for future Trust expenses........ (18,208) 106,654 (593,066)
------------ ------------ ------------
Distributable income............................................ $ 2,735,446 $ 5,501,938 $ 6,058,057
============ ============ ============
Distributions per Unit (4,751,510 Units)........................ $ .575699 $ 1.157932 $ 1.274973
============ ============ ============
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1999 1998 1997
<S> <C> <C> <C>
-------------- ------------ --------------
Trust corpus, beginning of year.............................. $ 442,621 $ 703,214 $ 938,589
Distributable income......................................... 2,735,446 5,501,938 6,058,057
Distributions to Unit holders................................ (2,735,446) (5,501,938) (6,058,057)
Amortization of overriding royalty interest.................. (74,853) (260,593) (235,375)
-------------- ------------ --------------
Trust corpus, end of year.................................... $ 367,768 $ 442,621 $ 703,214
============== ============ ==============
</TABLE>
See notes to financial statements.
39
<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, PennzEnergy Company ("PennzEnergy") acquired certain
oil and gas producing properties from Chevron, including four of the Royalty
Properties. The four Royalty Properties acquired by PennzEnergy were East
Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a
result of such acquisition, PennzEnergy replaced Chevron as the Working Interest
Owner of such properties on October 30, 1992. PennzEnergy also assumed Chevron's
obligations under the Conveyance with respect to such properties.
On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco")
acquired two of the Royalty Properties from Chevron. The Royalty Properties
acquired by Texaco were West Cameron 643 and East Cameron 371/381. As a result
of such acquisition, Texaco replaced Chevron as the Working Interest Owner of
such properties on December 1, 1994. Texaco also assumed Chevron's obligations
under the Conveyance with respect to such properties.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced
PennzEnergy as the Working Interest Owner of the East Cameron 354 and Eugene
Island 367 properties, respectively, on October 1, 1995, and also assumed
PennzEnergy's obligations under the Conveyance with respect to such properties.
Effective January 1, 1998 Energy Resource Technology, Inc. ("Energy")
acquired the East Cameron 354 property from SONAT. As a result of such
acquisition, Energy replaced SONAT as the Working Interest Owner of the East
Cameron 354 property effective January 1, 1998, and also assumed SONAT's
obligations under the Conveyance with respect to such property. In October 1998,
Amerada Hess Corporation ("Amerada") acquired the East Cameron 354 property
from Energy effective January 1, 1998. As a result of such acquisition, Amerada
replaced Energy as the Working Interest Owner of the East Cameron 354 property
effective January 1, 1998, and also assumed Energy's obligations under the
Conveyance with respect to such property.
40
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(1) TRUST ORGANIZATION AND PROVISIONS -- (CONTINUED)
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
Cameron 643 thereafter; PennzEnergy with respect to East Cameron 354, Eugene
Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30,
1992 until October 1, 1995, and with respect to Eugene Island 348 and Eugene
Island 208 thereafter; Texaco with respect to West Cameron 643 and East Cameron
371/381 for periods beginning on or after December 1, 1994; SONAT with respect
to East Cameron 354 for periods beginning on or after October 1, 1995; and Amoco
with respect to Eugene Island 367 for periods beginning on or after October 1,
1995; and Amerada with respect to East Cameron 354 for periods beginning on or
after January 1, 1998).
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. In the first quarter of 1998, the Trust determined
that the Trust's cash reserve was currently sufficient to provide for
future administrative expenses in connection with the winding up of the
Trust. The Trust determined that a cash reserve equal to three times the
average expenses of the Trust during
41
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(1) TRUST ORGANIZATION AND PROVISIONS -- (CONTINUED)
each of the past three years was sufficient at this time to provide for
future administrative expenses in connection with the winding up of the
Trust. This reserve amount for 1998 was $1,366,035. The excess amount of
$106,654 was distributed to Unit holders in the first quarter of 1998, and
no deposits were made to the Trust's cash reserve account during 1998. The
reserve amount for 1999 was $1,384,243. A deposit of $18,208 was made to
the Trust's cash reserve account in the first quarter of 1999. During the
second quarter of 1999, the Trust used $25,258 from the Trust's cash
reserve account to pay the Trust's general and administrative expenses,
when insufficient royalty income was received by the Trust. This $25,258
was redeposited to the Trust's cash reserve account during the third
quarter of 1999.
(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 revenues attributable to the Royalty were
estimated at $22.7 million as of October 31, 1999. (See Note 8 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., Richard L. Melton and Gary C. Evans
("Individual Trustees"), as trustees ("Trustees").
(2) NET OVERRIDING ROYALTY INTEREST
The Royalty entitles the Trust to its share (99.99%) of 25% of the Net
Proceeds attributable to the Royalty Properties. The Conveyance, dated January
1, 1983, provides that the Working Interest Owners will calculate, for each
period of three months commencing the first day of February, May, August and
November, an amount equal to 25% of the net proceeds from 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 91%, 98% and 32% of
crude oil revenues from the Royalty Properties during 1999, 1998 and 1997,
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 1999 ranged from $9.34 per bbl to $21.72 per
bbl. The average price of crude oil sold under this arrangement for February
2000 was approximately $28.68 per bbl. Sales to Texaco Inc. accounted for
approximately 9%, 2% and 68% of crude oil revenues from the Royalty Properties
during 1999, 1998 and 1997, respectively. Sales to Texaco Natural Gas Inc. and
Dynegy Inc. ("Dynegy") accounted for approximately 46% and 47%, respectively,
of total gas revenues from the Royalty Properties during 1999.
42
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(2) NET OVERRIDING ROYALTY INTEREST -- (CONTINUED)
The Trust's share of Royalty income was reduced by approximately $286,000,
$462,400 and $473,900 in 1999, 1998 and 1997, 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 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 net
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.
IMPAIRMENT OF LONG-LIVED ASSETS. The Trust reviews net overriding royalty
interest in oil and gas properties for possible impairment whenever events or
circumstances indicate the carrying amount of the asset may not be recoverable.
If there is an indication of impairment, the Trust prepares an estimate of
future cash flows (undiscounted and without interest charges) expected to result
from the use of the asset and its eventual disposition. If these cash flows are
less than the carrying amount of the asset, an impairment loss is recognized to
write down the asset to its estimated fair value. Preparation of estimated
expected future cash flows is inherently subjective and is based on management's
best estimate of assumptions concerning expected future conditions. There were
no write downs taken in the years presented.
(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
43
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(5) SPECIAL COST ESCROW ACCOUNT -- (CONTINUED)
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 $202,900, $225,000 and $215,900
for 1999, 1998 and 1997, respectively, serves to reduce the Trust's share of
allocated production costs. As of December 31, 1999, 1998 and 1997,
approximately $5,493,000, $3,329,000 and $4,622,000 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 2000, there was a net deposit of funds into the
Special Cost Escrow Account of approximately $265,000. The deposit was primarily
a result of an increase in the current estimate of 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 1999, the Working Interest Owners deposited a net amount of
approximately $1,587,400 into the Special Cost Escrow Account. The deposit was
primarily a result of an increase in the estimate of projected capital
expenditures of the Royalty Properties. In addition, there was a deposit
adjustment of approximately $576,500 made in the second quarter of 1999 due to a
release not being made in fourth quarter 1997.
In 1998, the Working Interest Owners released a net amount of approximately
$1,292,800 from the Special Cost Escrow Account. The release was made primarily
due to a decrease in the estimate of projected capital expenditures, production
costs and abandonment costs 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 current estimate of projected capital
expenditures, production costs and abandonment costs of 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, PennzEnergy, 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 $78,000, $42,300 and $166,100 was recovered
from the Trust by the Working Interest Owner during 1999, 1998 and 1997,
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
44
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(7) COMMITMENTS AND CONTINGENCIES -- (CONTINUED)
owned by PennzEnergy 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 PennzEnergy, it is estimated that Royalty income
attributable to such properties will be retained by PennzEnergy for the
remaining life of the Trust. The Trust does not anticipate that retention of
such Royalty income by PennzEnergy 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) 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 existing economic and operating conditions in effect
at October 31, 1999, 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,
1999, approximately 18,731 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 $11,200 in 1999
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,
1999, 1998 and 1997 included net proceeds relating to production of reserves
from the Royalty Properties for the twelve months ended October 31, 1999, 1998
and 1997, respectively. Accordingly, all reserve information included in the
tables below is as of October 31, 1999, 1998 and 1997.
45
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(8) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
Estimated net proved reserves attributable to the Partnership's net 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, 1996................................................................... 918,021 4,893,525
Additional disclosures:
Reserves related to PennzEnergy(d)............................................... (820) (28,172)
---------- ----------
October 31, 1996, net of reserves related to PennzEnergy......................... 917,201 4,865,353
========== ==========
October 31, 1996................................................................... 918,021 4,893,525
Revisions of previous estimates(a)................................................. 146,517 (156,820)
Extensions, discoveries and other additions........................................ 26,005 669,356
Royalty production................................................................. (374,154) (1,782,704)
---------- ----------
October 31, 1997................................................................... 716,389 3,623,357
Additional disclosures:
Reserves related to PennzEnergy(d)............................................... (2,292) (94,891)
---------- ----------
October 31, 1997, net of reserves related to PennzEnergy......................... 714,097 3,528,466
========== ==========
October 31, 1997................................................................... 716,389 3,623,357
Revisions of previous estimates(a)............................................... 250,454 1,405,224
Extensions, discoveries and other additions...................................... 11,053 1,241,385
Royalty production............................................................... (325,413) (2,551,534)
---------- ----------
October 31, 1998................................................................... 652,483 3,718,432
========== ==========
Additional disclosures:
Reserves related to PennzEnergy(d)............................................... (2,267) (78,165)
---------- ----------
October 31, 1998, net of reserves related to PennzEnergy......................... 650,216 3,640,267
========== ==========
October 31, 1999................................................................... 613,052 3,349,524
Additional disclosures:
Reserves related to PennzEnergy(d)............................................... (2,334) (67,582)
---------- ----------
October 31, 1999, net of reserves related to PennzEnergy......................... 610,718 3,281,942
========== ==========
Proved Developed Reserves:
October 31, 1995, net of reserves related to PennzEnergy........................... 200,653 811,935
========== ==========
October 31, 1996................................................................... 917,883 4,885,185
Additional disclosures:
Reserves related to PennzEnergy(d)............................................... (820) (28,172)
---------- ----------
October 31, 1996, net of reserves related to PennzEnergy......................... 917,063 4,857,013
========== ==========
October 31, 1997................................................................... 695,300 2,949,371
Additional disclosures:
Reserves related to PennzEnergy(d)............................................... (2,292) (94,891)
---------- ----------
October 31, 1997, net of reserves related to PennzEnergy......................... 693,008 2,854,480
========== ==========
October 31, 1998................................................................... 652,356 3,710,098
Additional disclosures:
Reserves related to PennzEnergy(d)............................................... (2,267) (78,165)
---------- ----------
October 31, 1998, net of reserves related to PennzEnergy......................... 650,089 3,631,933
October 31, 1999................................................................... 612,610 3,338,142
Additional disclosures:
Reserves related to PennzEnergy(d)............................................... (2,334) (67,582)
---------- ----------
October 31, 1999, net of reserves related to PennzEnergy......................... 610,276 3,270,560
========== ==========
</TABLE>
(SEE NOTES ON FOLLOWING PAGE)
46
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(8) 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, 1999, 1998 and 1997:
1999 1998 1997
--------- --------- ---------
(THOUSANDS)
Future Royalty income................ $ 22,680 $ 16,338 $ 25,224
Discount at 10% per annum............ (4,020) (2,774) (4,175)
--------- --------- ---------
Standardized measure of discounted
future Royalty income from proved
oil and gas reserves, discounted at
10% per annum(c)................... 18,660 13,564 21,049
Additional disclosures:
Amounts attributable to
PennzEnergy(d).................. (193) (155) (250)
--------- --------- ---------
Standardized measure of discounted
future Royalty income from
proved oil and gas reserves,
discounted at 10% per annum, net
of amounts attributable to
PennzEnergy(c).................. $ 18,467 $ 13,409 $ 20,799
========= ========= =========
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, 1999, 1998 and 1997:
1999 1998 1997
--------- --------- ---------
(THOUSANDS)
Beginning balance(c)................. $ 13,564 $ 21,049 $ 24,551
Revisions of previous
estimates(a).................... 5,278 (6,179) (263)
Extensions, discoveries and other
additions....................... 144 1,981 2,087
Royalty income..................... (2,953) (5,773) (7,003)
Accretion of discount.............. 1,356 2,105 2,455
Other(b)........................... 1,271 381 (778)
--------- --------- ---------
Net changes in standardized
measure................... 5,096 (7,485) (3,502)
--------- --------- ---------
Ending balance(c).................... 18,660 13,564 21,049
Additional disclosures:
Amounts attributable to
PennzEnergy(d).................. (193) (155) (250)
--------- --------- ---------
Ending balance, net of amounts
attributable to
PennzEnergy(c).................. $ 18,467 $ 13,409 $ 20,799
========= ========= =========
- ------------
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 PennzEnergy, discussed in Note 7
to the financial statements, the associated volumes and future royalty
income related to the PennzEnergy owned properties have been excluded from
the Trust's Supplemental Reserve Information, beginning in 1994.
47
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(9) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
Summarized quarterly financial data is as follows:
----------------------------------------------------------
FIRST SECOND THIRD FOURTH
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
1999*:
Royalty income.............. $ 88,696 $ 56,759 $ 687,942 $ 2,119,980
Distributable income........ $ 55,593 $ 0 $ 607,973 $ 2,071,880
Distributions per Unit...... $ .011700 $ .000000 $ .127953 $ .436046
1998*:
Royalty income.............. $ 1,934,392 $ 1,115,995 $ 896,202 $ 1,826,525
Distributable income........ $ 1,964,378 $ 1,015,656 $ 810,370 $ 1,711,534
Distributions per Unit...... $ .413421 $ .213754 $ .170549 $ .360208
</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.
48
<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.
The following information has been taken from filings with the Securities
and Exchange Commission on Form 13D and Form 4.
<TABLE>
<CAPTION>
AMOUNT
AND NATURE
OF PERCENT
TITLE OF CLASS OF NAME AND ADDRESS BENEFICIAL OF
VOTING SECURITIES OF BENEFICIAL OWNER OWNERSHIP(1) CLASS
- ------------------------------------- ------------------------------ ------------ --------
<S> <C> <C> <C>
Units of Beneficial Interest......... Magnum Hunter Resources, Inc. 1,923,871(2) 40.5
600 East Las Colinas
Blvd., Suite 1100
Irving, Tx 75039
</TABLE>
- ------------
(1) Under applicable regulations of the Securities and Exchange Commission,
securities are deemed to be "beneficially" owned by a person who directly
or indirectly holds or shares voting power or investment power with respect
thereto.
(2) Information obtained from Schedule 13D Amendment No. 1 dated January 5,
1999 and January 4, 2000, Magnum Hunter Resources, Inc. and Bluebird Energy,
Inc. ("Bluebird") and from Form 4's dated February 3, 1999. Bluebird is a
wholly owned subsidiary of Magnum Hunter and directly owns 1,855,689 Units.
Voting and dispositive power for these Units is shared between Magnum Hunter
and Bluebird. Magnum Hunter directly owns an additional 68,182 Units and has
sole voting and dispositive power with respect to such Units.
(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 Texaco, Inc. and the Supply and Distribution Department
of Chevron accounted for approximately 9% and 91%, respectively, of total crude
oil revenues from the Royalty Properties during 1998.
49
<PAGE>
The Trust's share of Royalty income was reduced by approximately $286,000
in 1999 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 1999.
Effective August 31, 1996, Chevron's Natural Gas Business Unit and Warren
Petroleum Company merged with Dynegy (formerly named NGC Corporation). In
connection with such merger, Chevron became one of three principal stockholders
of Dynegy, 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 Dynegy.
50
<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:
<TABLE>
<CAPTION>
PAGE IN THIS
FORM 10-K
<S> <C>
Independent Auditors' Report.............................................................. 37
Report of Independent Public Accountants.................................................. 38
Statements of Assets, Liabilities and Trust Corpus........................................ 39
Statements of Distributable Income........................................................ 39
Statements of Changes in Trust Corpus..................................................... 39
Notes to Financial Statements............................................................. 40
</TABLE>
(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> <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
A Form 8-K was filed with the Securities and Exchange Commission on
November 16, 1999.
51
<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 30TH DAY OF
MARCH, 2000.
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.
<TABLE>
<CAPTION>
SIGNATURE DATE
CHASE BANK OF TEXAS, NATIONAL
ASSOCIATION, Corporate Trustee
<S> <C>
By/s/PETE FOSTER March 30, 2000
PETE FOSTER
SENIOR VICE PRESIDENT
& TRUST OFFICER
INDIVIDUAL TRUSTEES
/s/GEORGE ALLMAN, JR. March 30, 2000
GEORGE ALLMAN, JR., TRUSTEE
/s/GARY C. EVANS March 30, 2000
GARY C. EVANS, TRUSTEE
/s/RICHARD L. MELTON March 30, 2000
RICHARD L. MELTON, TRUSTEE
</TABLE>
52
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENT OF ASSETS, LIABILITIES, AND TRUST CORPUS AS OF DEC-31-1999 AND THE
STATEMENT OF DISTRIBUTABLE INCOME FOR THE TWELVE MONTHS ENDED DEC-31-1999 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 3,456,123
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3,456,123
<PP&E> 28,267,655
<DEPRECIATION> 27,899,887
<TOTAL-ASSETS> 3,823,891
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 367,768
<TOTAL-LIABILITY-AND-EQUITY> 3,823,891
<SALES> 0
<TOTAL-REVENUES> 3,016,253
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 280,807
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 2,735,446
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,735,446
<EPS-BASIC> .575
<EPS-DILUTED> .575
</TABLE>
