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, 1995
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ________ TO________
COMMISSION FILE 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.)
TEXAS COMMERCE BANK
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 April 3, 1996, of $0.8125 was $3,860,601.88.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
As of April 3, 1996, 4,751,510 Units of Beneficial Interest in TEL Offshore
Trust.
Documents Incorporated By Reference: None
TABLE OF CONTENTS
PART I
PAGE
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........................... 10
Producing Acreage and Wells............................... 10
Reserves.................................................. 10
Operations and Production................................. 21
Marketing................................................... 21
Gas Marketing............................................. 22
Oil Marketing............................................. 22
Competition and Regulation.................................. 23
Competition............................................... 23
Regulation -- General..................................... 23
Natural Gas Pricing....................................... 23
Environmental Regulations................................. 26
Item 2. Properties.................................................... 28
Item 3. Legal Proceedings............................................. 28
Item 4. Submission of Matters to a Vote of Security Holders........... 28
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters........................................... 29
Item 6. Selected Financial Data....................................... 29
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................... 29
Item 8. Financial Statements and Supplementary Data................... 37
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure...................................... 48
PART III
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
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K............................................................ 50
SIGNATURES................................................................ 51
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NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-K are forward-looking
statements. Although the Working Interest Owners have advised the Trust that
they believe that the expectations reflected in the forward-looking statements
contained herein are reasonable, no assurance can be given that such
expectations will prove to have been correct. Important factors that could cause
actual results to differ materially from expectations ("Cautionary Statements")
are disclosed in this Form 10-K, including without limitation in conjunction
with the forward-looking statements included in this Form 10-K. All subsequent
written and oral forward-looking statements attributable to the Trust or persons
acting on its behalf are expressly qualified in their entirety by the Cautionary
Statements.
ii
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, Texas
Commerce Bank National Association ("Corporate Trustee"), 712 Main Street,
Houston, Texas 77002. The telephone number of the Trust is 713-216-5712. On
March 10, 1995, the Corporate Trustee was advised of the death of Horace C.
Bailey, one of the individual trustees of the Trust. In accordance with the
terms of the TEL Offshore Trust Agreement (the "Trust Agreement"), Richard L.
Melton was appointed by George Allman, Jr. and W. Leslie Duffy, the remaining
individual trustees, to replace Mr. Bailey effective April 20, 1995. The term
"Individual Trustees" as used herein includes Mr. Allman, Mr. Duffy, and, with
respect to time periods occurring on or after April 20, 1995, Mr. Melton. The
Individual Trustees and the Corporate Trustee may hereinafter collectively be
referred to as Trustees.
The principal asset of the Trust consists of a 99.99% interest in the TEL
Offshore Trust Partnership ("Partnership"). Chevron U.S.A. Inc. ("Chevron") owns
the remaining .01% interest in the Partnership. The Partnership owns an
overriding royalty interest ("Royalty"), equivalent to a 25% net profits
interest, in certain oil and gas properties (the "Royalty Properties") located
offshore Louisiana.
On November 18, 1988, Chevron acquired most of the Gulf of Mexico offshore
oil and gas properties of Tenneco Oil Company ("Tenneco"), including all the
Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as
the Working Interest Owner and Managing General Partner of the Partnership.
Chevron also assumed Tenneco's obligations under the instrument conveying the
Royalty to the Partnership (the "Conveyance").
On October 30, 1992, Pennzoil Company ("Pennzoil") acquired certain oil and
gas producing properties from Chevron, including four of the Royalty Properties.
The four Royalty Properties acquired by Pennzoil are East Cameron 354, Eugene
Island 348, Eugene Island 367 and Eugene Island 208. As a result of such
acquisition, Pennzoil replaced Chevron as the Working Interest Owner of such
properties on October 30, 1992. Pennzoil also assumed Chevron's obligations
under the Conveyance with respect to such properties.
On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco")
acquired one of the Royalty Properties from Chevron. The Royalty Property
acquired by Texaco was West Cameron 643. As a result of such acquisition, Texaco
replaced Chevron as the Working Interest Owner of such property on December 1,
1994. Texaco also assumed Chevron's obligations under the Conveyance with
respect to such property.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from Pennzoil. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
Pennzoil. As a result of such acquisitions, SONAT and Amoco have replaced
Pennzoil as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, and also have assumed Pennzoil's
obligations under the Conveyance with respect to such properties.
Chevron remains the Managing General Partner of the Partnership. The
Royalty Properties continue to be subject to the Royalty, and the Trust and
Partnership, in general, continue to operate as if the above-described sales of
the Royalty Properties had not occurred.
Unless the context in which such terms are used indicates otherwise, the
terms "Working Interest Owner" and "Working Interest Owners" as used herein
generally refer to the owner or owners of the Royalty Properties (Tenneco
Exploration, Ltd. through October 31, 1986; Tenneco for periods from
1
October 31, 1986 until November 18, 1988; Chevron with respect to all Royalty
Properties for periods from November 18, 1988 until October 30, 1992 and with
respect to all Royalty Properties except East Cameron 354, Eugene Island 348,
Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until
December 1, 1994 and with respect to the same properties except West Cameron 643
thereafter; Pennzoil with respect to East Cameron 354, Eugene Island 348, Eugene
Island 367 and Eugene Island 208 for periods from October 30, 1992 until October
1, 1995 and with respect to Eugene Island 348 and Eugene Island 208 thereafter;
Texaco with respect to West Cameron 643 for periods beginning on or after
December 1, 1994; SONAT with respect to East Cameron 354 for periods beginning
on or after October 1, 1995; and Amoco with respect to Eugene Island 367 for
periods beginning on or after October 1, 1995.)
A total of 4,751,510 units of beneficial interest in the Trust ("Units")
are issued and outstanding. The Units are traded on the National Association of
Securities Dealers Automated Quotation System Small-Cap Market under the symbol
TELOZ. From inception of the Trust to December 31, 1995, distributions to Unit
holders totaled approximately $68,125,000, or $14.33 per Unit.
The terms of 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 $7.7 million as of October 31, 1995. (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: (a) December 31, 2030, (b) the election of
the Trust to dissolve the Partnership, (c) the termination of the Trust, (d) the
bankruptcy of the Managing General Partner of the Partnership, (e) the
dissolution of the Managing General Partner or its election to dissolve the
Partnership; provided that the Managing General Partner has agreed not to elect
to dissolve the Partnership.
Under the Conveyance and the Partnership Agreement, the Trust is entitled
to its share (99.99%) of 25% of the Net Proceeds, as hereinafter defined,
realized from the sale of the oil, gas and associated hydrocarbons when produced
from the Royalty Properties. See "Description of Royalty Properties." The
Conveyance provides that the Working Interest Owners will calculate, for each
quarterly period commencing the first day of February, May, August and November,
an amount equal to 25% of the Net Proceeds from its oil and gas properties for
the period. "Net Proceeds" means for each quarterly period, the excess, if any,
of the Gross Proceeds, as hereinafter defined, for such period over Production
Costs, as hereinafter 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-
2
pay" payments or similar payments unless and until such payments are
extinguished or repaid through the future delivery of gas. "Production Costs"
means, generally, costs incurred on an accrual basis by the Working Interest
Owners in operating the Royalty Properties, including capital and non-capital
costs. In general, Net Proceeds are computed on an aggregate basis and consist
of the aggregate proceeds to the Working Interest Owners from the sale of oil
and gas from the Royalty Properties less (a) all direct costs, charges and
expenses incurred by the Working Interest Owners in exploration, production,
development, drilling and other operations on the Royalty Properties (including
secondary recovery operations); (b) all applicable taxes (including severance
and ad valorem taxes) excluding income taxes; (c) all operating charges directly
associated with the Royalty Properties; (d) an allowance for costs, computed on
a current basis at a rate equal to the prime rate of The Chase Manhattan Bank
(National Association) plus 1/2% on all amounts by which, and for only so long
as, costs and expenses for the Royalty Properties incurred for any quarter have
exceeded the proceeds of production from such Royalty Properties for such
quarter; (e) applicable charges for certain overhead expenses as provided in the
Conveyance; (f) the management fees and expense reimbursements owing the Working
Interest Owners; and (g) a cash reserve for the future costs to be incurred by
the Working Interest Owners to plug and abandon wells and dismantle and remove
platforms, pipelines and other production facilities from the Royalty Properties
and for future drilling projects and other estimated future capital expenditures
on the Royalty Properties. The Trustees are not obligated to return any royalty
income received in any period, but future amounts otherwise payable shall be
reduced by the amount of any prior overpayments of such royalty income. The
Working Interest Owners are required to maintain books and records sufficient to
determine amounts payable under the Royalty. The Working Interest Owners are
also required to deliver to the Corporate Trustee a statement of the computation
of Net Proceeds no later than the tenth business day prior to the quarterly
record date.
The Royalty Properties are required to be operated in accordance with
standards applicable to a prudent oil and gas operator. The Working Interest
Owners are free to transfer their working interest in any of the Royalty
Properties (burdened by the Royalty) to third parties. The Working Interest
Owners are also free to enter into farm-out agreements whereby a Working
Interest Owner would transfer a portion of its interest (unburdened by the
Royalty) while retaining a lesser interest (burdened by the Royalty) in return
for the transferee's obligation to drill a well on the Royalty Properties. The
Working Interest Owners have the right to abandon any well or lease and upon
termination of any lease, the part of the Royalty relating thereto will be
extinguished. The Royalty Properties are primarily operated by the Working
Interest Owners although certain other parties operate some of the Royalty
Properties.
The discussions of terms of the Trust Agreement, Partnership Agreement and
Conveyance contained herein are qualified in their entirety by reference to the
Trust Agreement, Partnership Agreement and Conveyance themselves, which are
exhibits to this Form 10-K and are available upon request from the Corporate
Trustee.
The Trust has no employees. Administrative functions of the Trust are
performed by the Corporate Trustee.
HISTORY OF THE TRUST
Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the Trust
effective January 1, 1983, pursuant to a Plan of Dissolution ("Plan"), which was
approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance
with the Plan, the assets of Tenneco Offshore were transferred to the Trust as
of January 1, 1983, and Units were exchanged for shares of common stock of
Tenneco Offshore on the basis of one Unit for each share of common stock held by
stockholders of record on January 14, 1983. Additionally, the Partnership was
formed, in which the Trust owned a 99.99% interest and Tenneco owned a .01%
interest. The Partnership was formed solely for the purpose of owning the
Royalty, receiving the proceeds from the Royalty, paying the liabilities and
expenses of the Partnership and disbursing remaining 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
3
Tenneco Exploration, Ltd. ("Exploration I") located offshore Louisiana to the
Partnership, contributing the common stock of Tenneco Offshore II Company
("Offshore II") to the Trust, and issuing certificates evidencing Units in
liquidation and cancellation of Tenneco Offshore's common stock.
On October 31, 1986, Exploration I was dissolved and the oil and gas
properties of Exploration I were distributed to Tenneco subject to the Royalty.
Tenneco, who was then serving as the Managing General Partner of the
Partnership, assumed the obligations of Exploration I, including its obligations
under the Conveyance. The dissolution of Exploration I had no impact on future
cash distributions to Unit holders.
As discussed above, on November 18, 1988, Chevron replaced Tenneco as the
Working Interest Owner and Managing General Partner of the Partnership and
assumed Tenneco's obligations under the Conveyance. On October 30, 1992,
Pennzoil acquired certain oil and gas producing properties from Chevron,
including four of the Royalty Properties. The four Royalty Properties acquired
by Pennzoil are East Cameron 354, Eugene Island 348, Eugene Island 367 and
Eugene Island 208. As a result of such acquisition, Pennzoil replaced Chevron as
the Working Interest Owner of such properties and assumed Chevron's obligations
under the Conveyance with respect to such properties on October 30, 1992. On
December 1, 1994, Texaco acquired one of the Royalty Properies from Chevron. The
Royalty Property acquired by Texaco is West Cameron 643. As a result of such
acquisition, Texaco replaced Chevron as the Working Interest Owner of such
property and assumed Chevron's obligations under the Conveyance with respect to
such property on December 1, 1994. On October 1, 1995, SONAT and Amoco acquired
the East Cameron 354 and Eugene Island 367 properties, respectively, from
Pennzoil. As a result of such acquisitions, SONAT and Amoco have replaced
Pennzoil as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, and also have assumed Pennzoil's
obligations under the Conveyance with respect to such properties.
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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
5
purchase are more fully described in the Trust Agreement. The Trustee
shall cancel any Units acquired in accordance with the foregoing
procedures thereby increasing the proportionate interest in the Trust of
other holders of Units.
(iii) The Trustees may, in their sole discretion, cause the Trust
to borrow any amounts required to purchase Units in accordance with the
procedures described above.
LIABILITY OF UNIT HOLDERS
It is the intention of the Working Interest Owners and the Trustees that
the Trust be an "express trust" under the Texas Trust Act. Under Texas law,
beneficiaries of an express trust are not personally liable for the obligations
of the trust, even if the assets of the trust are insufficient to discharge its
obligations. However, it is unclear under Texas law whether the Trust will be
held to constitute an express trust and, if it is not held to be an express
trust, whether the holders of Units would be jointly and severally liable for
the obligations of the Trust as would general partners of a partnership.
Under current judicial decisions, the Federal Energy Regulatory Commission
("FERC") is not considered to be empowered to compel refunds from overriding
royalty interest owners with respect to gas price overcharges. However, future
laws, regulations or judicial decisions might permit the FERC or other
governmental agencies to require such refunds from overriding royalty interest
owners or create filing, reporting or certification obligations with respect to
a trust created for such overriding royalty interest owners. Moreover, other
parties, such as oil or gas purchasers, may be able to instigate private
lawsuits or other legal action to compel refunds from overriding royalty
interest owners with respect to oil or gas pricing overcharges.
The Working Interest Owners have agreed that they will not seek to recover
from the Unit holders the amount of any refunds they are required to make except
out of future revenues payable to the Trust. The Trustees will be liable to the
Unit holders if the Trustees allow any liability to be incurred without taking
any and all action necessary to ensure that such liability will be satisfiable
only out of the Trust assets (regardless of whether the assets are adequate to
satisfy the liability) and will be non-recourse to the Unit holders. However,
the Trustees will not be liable to the Unit holders for state or federal income
taxes or for refunds, fines, penalties or interest relating to oil or gas
pricing overcharges under state or federal price controls. The Trustees will be
indemnified from the Trust assets, to the extent that the Trustees' actions do
not constitute gross negligence, fraud or misconduct.
Each Unit holder should consider, in weighing the possible exposure to
liability in the event the Trust were not classified as an express trust, (a)
the substantial value and passive nature of the Trust assets, (b) the
restrictions on the power of the Trustees to incur liabilities on behalf of the
Trust and (c) the limited activities to be conducted by the Trustees.
FEDERAL INCOME TAX MATTERS
OWNERSHIP OF UNITS
The IRS has ruled that the Trust is a grantor trust and that the
Partnership is a partnership for federal income tax purposes. Thus, the Trust
will incur no federal income tax liability, each Unit holder will be treated as
owning an interest in the Partnership and each Unit holder of record as of the
last business day of each quarter will be allocated a share of the income and
deductions of the Trust, including the Trust's share of the income and
deductions of the Partnership (computed on an accrual basis), for such quarter.
Also, each Unit holder will be entitled to compute cost depletion with respect
to his share of income from the Royalty based on his basis in the Royalty. A
Unit holder will have a basis in the Royalty equal to the basis in his Units.
Unit holders that acquired Units after October 11, 1990, are entitled to
percentage depletion on Royalty income attributable to such Units.
Since the IRS has ruled that the Trust is a grantor trust and that the
Partnership is a partnership for federal income tax purposes, the Trustees will
treat each Unit holder as owning an interest in the Partnership and will report
to the Unit holders in a manner consistent with the Trust Agreement and the
Partnership Agreement, allocating income and deductions of the Partnership and
the Trust for each
6
quarter to the Unit holders of record as of the last business day of such
quarter. Also, since the IRS has ruled that the Royalty is a non-operating
economic interest giving rise to income subject to depletion, the Trustees will
treat the Royalty as a single property giving rise to income subject to
depletion, although the computation of depletion will be made by each Unit
holder based upon information provided by the Trustees.
The Tax Reform Act of 1986 made significant changes as to the
classification of certain income and expense items. Royalty income is considered
portfolio income. Since all income from the Partnership is royalty income, this
amount, net of depletion, is portfolio income and, under the Revenue Act of
1987, subject to certain exceptions and transitional rules, such royalty income
cannot be offset by losses from passive businesses. Additionally, interest
income is portfolio income. Administrative expense is an investment expense.
BACKUP WITHHOLDING
Distributions from the Trust are generally subject to backup withholding at
a rate of 31% of such distributions. Backup withholding will not normally apply
to distributions to a Unit holder, however, unless such Unit holder fails to
properly provide to the Trust his taxpayer identification number ("TIN") or the
IRS notifies the Trust that the TIN provided by such Unit holder is incorrect.
SALE OF UNITS
Generally, except for recapture items, the sale, exchange or other
disposition of a Unit will result in capital gain or loss measured by the
difference between the basis in the Unit and the amount realized. Such gain or
loss would be capital gain or loss if such Unit was held by the Unit holder as a
capital asset, either long-term or short-term depending on the holding period of
the Unit and the then minimum period required to avoid short-term gain or loss.
Presently, such period is more than one year for Units acquired before June 23,
1984, or after December 31, 1987. For Units acquired on or between such dates,
such period is more than six months. Effective for property placed in service
after December 31, 1986, the amount of gain, if any, realized upon the
disposition of oil and gas property is treated as ordinary income to the extent
of the intangible drilling and development costs incurred with respect to the
property and depletion claimed with respect to such property to the extent it
reduced the taxpayer's basis in the property. Although it is not clear, under
this provision, it is expected that depletion attributable to a positive Section
743(b) basis adjustment of a Unit acquired after 1986 will 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 prior to March
14, 1995. Upon a disposition of a Unit acquired after 1986 or disposition of an
oil and gas property to which the depletion is attributable, either occurring
after March 13, 1995, depletion attributable to a positive Section 743(b)
adjustment will be subject to recapture as ordinary income. The balance of any
gain or any loss will be capital gain or loss if such Unit was held by the Unit
holder as a capital asset.
FOREIGN UNIT HOLDERS
In general, a Unit holder who is a nonresident alien individual or which is
a foreign corporation (collectively "Foreign Taxpayer") will be subject to tax
on the gross income produced by the Royalty at a rate equal to 30% (or lower
treaty rate, if applicable). This tax will be withheld by the Trustees and
remitted directly to the United States Treasury. A Foreign Taxpayer may elect to
treat the income from the Royalty as effectively connected with the conduct of a
United States trade or business under Section 871 or Section 882 of the Internal
Revenue Code of 1986, as amended (the "Code") (or pursuant to any similar
provisions of applicable treaties). Upon making such election such Unit holder
is entitled to claim all deductions with respect to such income, but he must
file a United States income tax return to claim such deductions. This election
once made is irrevocable (unless an applicable treaty allows the election to be
made annually). However, for tax years beginning after December 31, 1987, such
effectively connected income will be 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.
7
Section 897 of the Code and the Treasury Regulations thereunder treat the
publicly traded Trust as if it were a United States real property holding
corporation. Accordingly, Foreign Unit holders owning greater than 5 percent of
the outstanding Units (or 237,576 Units) are subject to United States income tax
on the gain on the disposition of their Units. Foreign Unit holders owning less
than 5 percent are not subject to United States income tax on the gain on the
disposition of their Units.
Federal income taxation of a Foreign Taxpayer is a highly complex matter
which may be affected by many other considerations. Therefore, each Foreign
Taxpayer should consult his own tax adviser as to the advisability of his
ownership of Units.
TAX-EXEMPT ORGANIZATIONS
The Revenue Reconciliation Act of 1993 repealed the rule that automatically
characterized a tax-exempt organization's share of a publicly traded
partnership's gross income as derived from an unrelated trade or business.
Beginning in 1994, investments in publicly traded partnerships are treated the
same as investments in other partnerships for purposes of the rules governing
unrelated business taxable income. The Royalty and interest income of the
Partnership should not be unrelated business taxable income so long as,
generally, a Unit holder did not incur debt to acquire a Unit or otherwise incur
or maintain a debt that would not have been incurred or maintained if such Unit
had not been acquired. Legislative proposals have been made from time to time
which, if adopted, would result in the treatment of Royalty income as unrelated
business income. Tax-exempt Unit holders should consult their own tax advisors
with respect to the treatment of Royalty income.
STATE LAW CONSIDERATIONS
The Trust and the Partnership have been structured so as to cause the Units
to be treated for certain state law purposes essentially the same as other
securities, that is, as interests in intangible personal property rather than as
interests in real property. However, in the absence of controlling legal
precedent, there is a possibility that under certain circumstances a Unit holder
could be treated as owning an interest in real property under the laws of
Louisiana. In that event, the tax, probate, devolution of title and
administration laws of Louisiana or other states applicable to real property may
apply to the Units, even if held by a person who is not a resident thereof.
Application of such laws could make the inheritance and related matters with
respect to the Units substantially more onerous than had the Units been treated
as interests in intangible personal property. Unit holders should consult their
legal and tax advisers regarding the applicability of these considerations to
their individual circumstances.
TERMINATION OF THE TRUST
The terms of the TEL Offshore Trust Agreement provide that the Trust will
terminate upon the first to occur of the following events: (1) total future net
revenues attributable to the Partnership's interest in the Royalty, as
determined by independent petroleum engineers, as of the end of any year, are
less than $2 million or (2) a decision to terminate the Trust by the affirmative
vote of Unit holders representing a majority of the Units. Total future net
revenues attributable to the Partnership's interest in the Royalty were
estimated at $7.7 million as of October 31, 1995, 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, 1995, it
is estimated that approximately 70% of future net revenues from the Royalty
Properties are expected to be received by the Trust during the next 4 years.
Because the Trust will terminate in the event estimated future net revenues fall
below $2 million, it would be possible for the Trust to terminate even though
some or all of the Royalty Properties continued to have remaining productive
lives. Upon termination of the Trust, the Trustees will sell for cash all of the
assets held in the Trust estate and make a final distribution to Unit holders of
any funds remaining after all Trust liabilities have been satisfied. The
estimates of future net revenues discussed above are subject to the limitations
described in the DeGolyer and MacNaughton reserve study. The reserve study is
limited to reserves classified as proved; therefore, future capital
8
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.
In addition, in the event of a dissolution of the Partnership (which could
occur under the circumstances described above under "Description of the Trust")
and a subsequent winding up and termination thereof, the assets of the
Partnership (i.e., the Royalty) could either (i) be distributed in kind ratably
to the Trust and the Managing General Partner or (ii) be sold and the proceeds
thereof distributed ratably to the Trust and the Managing General Partner. In
the event of a sale of the Royalty and a distribution of the cash proceeds
thereof to the Trust and the Managing General Partner, the Trustee would make a
final distribution to Unit holders of the Trust's portion of such cash proceeds
plus any other cash held by the Trust after payment of or provision for all
liabilities of the Trust, and the Trust would be terminated.
ROYALTY INCOME, DISTRIBUTABLE INCOME AND TOTAL ASSETS
Reference is made to Items 6, 7 and 8 of this Form 10-K for financial
information relating to the Trust.
9
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, 1995
WORKING ---------------------------
INTEREST
OWNER'S WELLS SUCCESS-
ACQUISITION OWNERSHIP DRILLED(1) FUL(2)(3)
DATE INTEREST GROSS ------------- ----------
PROPERTY (MO.-YR.) (%) ACRES EXPL. DEV. OIL GAS
- ---------------------------------------------------- ----------- --------- --------- ----- ---- --- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
East Cameron 354.................................... 12-72 50.00 5,000 2 4 0 5
West Cameron 643.................................... 12-72 50.00 5,000 2 17 0 13
Eugene Island 339................................... 12-72 50.00 5,000 2 29 27 0
Eugene Island 342................................... 12-72 1.00 5,000 2 20 0 16
Eugene Island 343................................... 12-72 1.00 5,000 4 16 0 17
Eugene Island 348................................... 12-72 50.00 5,000 4 5 0 7
West Cameron 642.................................... 1-73 25.00 5,000 3 7 0 7
East Cameron 370.................................... 1-73 25.00 5,000 3 1 0 4
East Cameron 371.................................... 1-73 25.00 5,000 3 1 0 1
Vermilion 246....................................... 1-73 36.30 5,000 3 2 0 3
West Cameron 41 E/2................................. 3-74 .30 2,500 -- 2 0 2
Ship Shoal 183 N/2.................................. 12-73 66.70 2,500 -- 21 21 0
Ship Shoal 183 NW/4 of S/2.......................... 4-77 50.00 625 -- 1 1 0
Ship Shoal 183 NE/4 of SW/4
of S/2, SE/4...................................... 12-82 50.00 1,875 1 -- 1 0
Eugene Island 208................................... 8-73 100.00 1,250 -- 3 0 3
Eugene Island 367................................... 3-74 1.60 5,000 2 9 0 9
South Marsh Island 252.............................. 3-74 .22 4,997 2 -- 0 1
South Timbalier 36.................................. 3-74 .30 5,000 2 20 9 11
South Timbalier 37.................................. 3-74 .30 5,000 3 12 11 1
--------- ----- ---- --- ---
78,747 38 170 70 100
--------- ----- ---- --- ---
--------- ----- ---- --- ---
</TABLE>
- ------------
(1) As of October 31, 1995, there were no wells in the process of drilling.
See "Operations" under Item 7 of this report for a discussion of drilling
activity during 1995 and the first half of 1996.
(2) As of October 31, 1995, there were 75 producing completions.
(3) Multiple completions are counted as one well. South Timbalier 36 has 3
multiple completion wells and South Timbalier 37 has 6 multiple completion
wells.
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,
1995. The following letter summarizes such reserve study. Such study reflects
estimated production, reserve quantities and future net revenue based upon
estimates of the future timing of actual production without regard to when
received by the Trust, which differs from the manner in which the Trust
recognizes its royalty income. See Notes 3 and 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,
10
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,
1995, approximately 265,300 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 $306,800 in 1995
related to such imbalance. Chevron has advised the Trust that sufficient gas
reserves exist on Eugene Island 339 for underproduced parties to recoup their
share of the gas imbalance on that property.
During 1994, Pennzoil, the Working Interest Owner on the Eugene Island 348
property, settled the 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 $5,000 and $150,000 was recovered from the
Trust by the Working Interest Owner during 1994 and 1995, respectively, and the
remainder will be subject to recovery from the Trust in future periods, in
accordance with the Conveyance. The Working Interest Owner has advised the Trust
that future Royalty income attributable to all of the Royalty Properties owned
by Pennzoil will be used to offset the Trust's share of such settlement amounts.
Based on current production, prices and expenses for the Royalty Properties
owned by Pennzoil, it is estimated that Royalty income attributable to such
properties will be retained by Pennzoil for the remaining life of the Trust. The
Trust does not anticipate that retention of such Royalty income by Pennzoil will
have a material effect on the Trust's Royalty income as a whole.
11
DEGOLYER AND MACNAUGHTON
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
April 8, 1996
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,
1995, of the extent and value of the proved crude oil, condensate, and natural
gas reserves of a net profits interest owned by TEL Offshore Trust Partnership
(the Trust Partnership). This net profits interest (the Trust Partnership
Interest) is in certain offshore leases owned by Chevron USA Inc. (Chevron), as
successor in title to Tenneco Oil Company (Tenneco), by Pennzoil Petroleum
Company (Pennzoil), as successor in title to Chevron, and by Texaco Exploration
and Production, Inc. (Texaco), as successor in title to Chevron. The interest
appraised consists of a 25-percent net profits interest in 19 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.
Our reserve 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 in
similar reservoirs, consideration of the state of development of the reservoir,
and the quality and completeness of basic data.
12
Estimates of oil, condensate, and gas reserves and future net revenues
should be regarded only as estimates that may change as further production
history and additional information become available. Not only are such reserves
and revenue estimates based on that information which is currently available,
but such estimates are also subject to the uncertainties inherent in the
application of judgmental factors in interpreting such information.
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 our
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.
Petroleum reserves included in this report are classified as proved and
are judged to be economically producible in future years from known reservoirs
under existing economic and operating conditions and assuming continuation of
current regulatory practices using conventional production methods and
equipment. In the analyses of production-decline curves, reserves were estimated
only to the limit of economic rates of production under existing economic and
operating conditions using prices and costs as of the date the estimate is made,
including consideration of changes in existing prices provided only by
contractual arrangements but not including escalations based upon future
conditions. The petroleum reserves are classified as follows:
PROVED -- Reserves that have been proved to a high degree of certainty
by analysis of the producing history of a reservoir and/or by
volumetric analysis of adequate geological and engineering data.
Commercial productivity has been established by actual production,
successful testing, or in certain cases by favorable core analyses and
electrical-log interpretation when the producing characteristics of the
formation are known from nearby fields. Volumetrically, the structure,
areal extent, volume, and characteristics of the reservoir are well
defined by a reasonable interpretation of adequate subsurface well
control and by known continuity of hydrocarbon-saturated material above
known
13
fluid contacts, if any, or above the lowest known structural occurrence
of hydrocarbons.
DEVELOPED -- Reserves that are recoverable from existing wells with
current operating methods and expenses.
Developed reserves include both producing and nonproducing reserves.
Estimates of producing reserves assume recovery by existing wells
producing from present completion intervals with normal operating
methods and expenses. Developed nonproducing reserves are in reservoirs
behind the casing or at minor depths below the producing zone and are
considered proved by production from other wells in the field, by
successful drill-stem tests, or by core analyses from the particular
zones. Nonproducing reserves require only moderate expense to be
brought into production.
UNDEVELOPED -- Reserves that are recoverable from additional wells yet
to be drilled.
Undeveloped reserves are those considered proved for production by
reasonable geological interpretation of adequate subsurface control in
reservoirs that are producing or proved by other wells but are not
recoverable from existing wells. This classification of reserves
requires drilling of additional wells, major deepening of existing
wells, or installation of enhanced recovery or other facilities.
Reserves recoverable by enhanced recovery methods, such as injection of
external fluids to provide energy not inherent in the reservoirs, may be
classified as proved developed or proved undeveloped reserves depending upon the
extent to which such enhanced recovery methods are in operation. These reserves
are considered to be proved only in cases where a successful fluid-injection
program is in operation, a pilot program indicates successful fluid injection,
or information is available concerning the successful application of such
methods in the same reservoir and it is reasonably certain that the program will
be implemented.
The properties evaluated consist of 19 leases located offshore from
Louisiana.
14
These 19 leases include 14 productive properties (including 2 leases covering
separate portions of the south half of Ship Shoal Block 183) and 5 leases to
which no reserves have been assigned. Pennzoil has an interest in three of the
productive properties and one of the leases to which no reserves have been
assigned. Texaco has an interest
in two of the productive properties. Capital costs for abandonment have been
included for these properties, including four of the leases which are
considered depleted and to which no reserves have been assigned.
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. This 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.
Reserves estimated in this report 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, 1995. 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.
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, or Texaco. 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> <C>
Trust Partnership Interest
future net revenue
Trust Partnership Interest net reserves = ------------------------------- X Combined net reserves
Combined future gross revenue
</TABLE>
This formula was applied separately to the Pennzoil and Texaco 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.
15
Because the net reserves volumes attributable to the Trust Partnership Interest
are estimated using an allocation of reserves based on estimates of future
revenue, a change in prices or costs will result in changes in the estimated net
reserves. Therefore, the estimated net reserves attributable to the Trust
Partnership Interest will vary if different future price and cost assumptions
are used. Trust Partnership Interest net revenue and net reserves estimates
included in this report have been estimated from reserves and revenue
attributable to the combined interests using procedures and calculation methods
as specified by Chevron and represented by Chevron to be in accordance with the
Conveyance of Overriding Royalty Interests.
Units have been formed for several common reservoirs that underlie the
Subject Properties and adjacent leases. In these cases, the estimated gross
reserves of the entire reservoir are shown and the resulting combined Trust
Partnership and Chevron, Pennzoil, or Texaco interests in the reservoir unit are
used to calculate combined interests net reserves.
Data available from wells drilled on the appraised properties through
October 1995 were used in estimating gross ultimate recovery. Gross production
estimated through October 31, 1995, 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 2 months, since production data for
certain properties were available only through August 1995.
Net proved reserves attributable to the Trust Partnership Interest, as
of October 31, 1995, are estimated as follows:
OIL AND NATURAL
CONDENSATE GAS
(BBL) (MCF)
----------- ---------
Proved and Undeveloped Reserves
Reserves as of October 31, 1994 223,067 1,890,489
Revisions of Previous Estimates 185,986 (216,130)
Improved Recovery 0 0
Purchases of Minerals in Place 0 0
Extensions, Discoveries, and
Other Additions 0 0
Production (73,078) (235,036)
Sales of Minerals in Place 0 0
Reserves as of October 31, 1995 335,975 1,439,323
Proved Developed Reserves
Reserves as of October 31, 1994 222,930 1,882,153
Reserves as of October 31, 1995 201,110 922,502
16
Gas volumes shown herein are salable gas volumes and are expressed at a
temperature base of 60 degrees Fahrenheit and a pressure base of 14.73 pounds
per square inch absolute. Condensate reserves estimated herein are those to be
obtained from normal separator recovery.
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 1996. The future accrual or escrow
amounts for each of the three 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 4.5 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 three groups of the properties (Chevron, Pennzoil, and Texaco). Interest was
charged monthly on the net profits deficit balances (costs not recovered
currently) at the rate of 4.5 percent per year as specified by Chevron. Present
worth is defined as future net revenue discounted at a specified arbitrary
discount rate compounded monthly over the expected period of realization; in
this report, present worth values using a discount rate of 10 percent are
reported. Future income tax expenses were not taken into account in estimating
future net revenue and present worth. No deductions were made in the foregoing
reserves for any outstanding production payments.
Revenue values in this report were estimated using the initial prices
and costs provided by Chevron. Future prices were estimated using guidelines
established by the Securities and Exchange Commission and the Financial
Accounting Standards Board. These guidelines require the use of prices for oil
and condensate in effect on October 31, 1995. 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
17
receive on October 31, 1995. The assumptions used for estimating future prices
and costs are as follows:
OIL AND CONDENSATE PRICES
Oil and condensate prices applicable in October 1995 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, 1995, 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 1995 values and were not
adjusted for inflation.
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
18
present worth attributable to the Trust Partnership Interest, as of October 31,
1995, is as follows:
<TABLE>
<CAPTION>
CHEVRON PENNZOIL TEXACO
PROPERTIES PROPERTIES PROPERTIES TOTAL
---------- ---------- ---------- ----------
COMBINED INTEREST
<S> <C> <C> <C> <C>
Future Gross Revenue ($) 50,324,985 2,147,058 7,722,689 60,194,732
Operating Costs ($) (15,322,883) (607,160) (2,605,260) (18,535,303)
Capital Costs ($)(1) (12,887,820) (1,159,753) (8,326,932) (22,374,505)
Future Net Revenue ($) 22,114,282 380,145 (3,209,503) 19,284,924
Cost Escrow as of 10-31-95 ($) 8,388,752 333,339 1,585,139 10,307,230
Interest Credit on Accrued Balance
($) 1,924,637 226,676 1,036,324 3,187,637
Interest on Deficit ($) (18,693) (39,692) (863,791) (922,176)
Overhead ($) (2,413,597) (124,144) (590,634) (3,128,375)
Revenue Subject to Net Profits
Interest ($) 29,995,381 776,324 (2,042,465) 28,729,240
TRUST PARTNERSHIP INTEREST
Future Net Revenue ($)(2) 7,498,794 194,067 0(3) 7,692,861
Present Worth at 10 Percent ($)(2) 5,384,383 140,389 0(3) 5,524,772
</TABLE>
(1) Includes abandonment costs.
(2) Future income tax expenses were not taken into account in the preparation
of these estimates.
(3) Texaco properties do not contribute revenue to the Trust Partnership due
to future estimated abandonment costs.
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 Financial Accounting Standards Board and Rules 4-10(a) (1)-(13) of
Regulation S-X and Rule 302(b) of Regulation S-K of the Securities and Exchange
Commission; 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.
19
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.
Submitted,
By: /s/ DEGOLYER AND MACNAUGHTON
------------------------
DeGOLYER and MacNAUGHTON
STATE OF TEXAS
JAMES W. HAIL, JR.
42919
REGISTERED
PROFESSIONAL ENGINEER
By: /s/ JAMES W. HAIL, JR., P.E.
------------------------
James W. Hail, Jr., P.E.
Senior Vice President
DeGolyer and MacNaughton
20
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 $450,000 annually. The costs and expenses of the Trust
may increase in future years, depending on increases in accounting, engineering,
legal and other professional fees and 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 million. See "Business -- Termination of the Trust".
Except with respect to the West Cameron 643 property, as discussed below,
the Working Interest Owners have advised the Trust that there have been no
events subsequent to October 31, 1995 that have caused a significant change in
the estimated proved reserves referred to in the DeGolyer and MacNaughton
letter. The Working Interest Owner has advised the Trust that as a result of
recent drilling, its estimates of proved reserves on the West Cameron 643
property have increased by approximately 3,000 barrels of crude oil and
condensate (750 barrels net to the Trust) and 2,400,000 Mcf of gas (600,000 Mcf
net to the Trust).
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. Recently the demand for oil and gas has been greater than the oil and
gas deliverability and has caused an increase in oil and gas prices.
Spot domestic natural gas prices have generally increased in late 1995 and
early 1996 and are higher than gas prices in early 1995. Crude oil prices in
1996 have increased from levels in late 1995 and are higher than crude oil
prices in early 1995.
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.
21
GAS MARKETING
During 1995, gas sales by the Working Interest Owners under a contract with
Tennessee Gas Pipeline Company ("Tennessee Gas") accounted for 42% of total gas
revenues from the Royalty Properties. Such contract, as amended, provides for
gas to be purchased by Tennessee Gas at a calculated monthly price based on the
spot market rate and contains release provisions for gas not taken by Tennessee
Gas. The majority of the remaining gas revenues were attributable to gas
purchases by Columbia Gulf Transmission Company (31%) and Penn Union (21%).
It should be noted that the Conveyance provides that amounts received by
the producer pursuant to "take-or-pay" provisions are not included within the
Royalty payable to the Trust unless and until gas is actually delivered pursuant
to the "make-up" provisions, if any, of the applicable contract. Accordingly,
amounts received by the Working Interest Owners as "take-or-pay" payments are
not included in the calculation of the Royalty payable, and the income received
by the Trust is restricted to amounts paid for gas actually delivered.
Due to the seasonal nature of demand for natural gas and its effects on
sales prices and production volumes, the amount of gas sold with respect to the
Royalty Properties may vary. Generally, production volumes and prices are higher
during the first and fourth quarters of each calendar year. Because of the time
lag between the date on which the Working Interest Owners receive payment for
production from the Royalty Properties and the date on which distributions are
made to Unit holders, the seasonality that generally affects production volumes
and prices of is generally reflected in distributions to the Trust in later
periods.
The following paragraphs discuss the marketing of gas from the principal
Royalty Properties.
EUGENE ISLAND 339. Eugene Island 339 contributed approximately 32% of the
revenues from gas sales from the Royalty Properties in 1995. The average price
received for natural gas from all of the Working Interest Owner's purchasers on
Eugene Island 339 during 1995 was $1.79 per Mcf and the price received for
February 1996 was $2.35 per Mcf. The gas from Eugene Island 339 is committed to
Tennessee Gas pursuant to the contract discussed above.
WEST CAMERON 643. West Cameron 643 contributed approximately 29% of the
revenues from gas sales from the Royalty Properties in 1995. The average price
received for natural gas from all of the Working Interest Owner's purchasers on
West Cameron 643 during 1995 was $1.58 per Mcf and the price received for
February 1996 was $2.48 per Mcf.
SHIP SHOAL 182/183. Ship Shoal 182/183 contributed approximately 15% of the
revenues from gas sales from the Royalty Properties in 1995. The average price
received for natural gas from all of the Working Interest Owner's purchasers on
Ship Shoal 182/183 during 1995 was $1.74 per Mcf and the price received for
February 1996 was $2.61 per Mcf. The gas from Ship Shoal 182/183 is committed
under the contract with Tennessee Gas discussed above.
OIL MARKETING
Crude oil purchases by the Supply and Distribution Department of Chevron
and by Texaco Inc. accounted for approximately 73% and 24%, respectively, of
total crude oil revenues from the Royalty Properties during 1995.
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 1995
ranged from $15.33 per bbl to $17.93 per bbl. The average price of crude oil
sold under this arrangement for February 1996 was approximately $17.25 per bbl.
Texaco Inc. purchases crude oil at prices based on its own published
pricing bulletin with an adjustment for gravity and transportation charges.
Average monthly prices for fiscal 1995 ranged from $14.48 per bbl to $17.27 per
bbl. The average crude oil price under this arrangement for February 1996 was
approximately $17.86 per bbl.
22
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 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.
NATURAL GAS PRICING
The Natural Gas Policy Act of 1978 ("NGPA"), which became effective on
December 1, 1978, established maximum ceiling prices for certain categories of
natural gas sold in either interstate or intrastate commerce. The NGPA
classifies gas into various categories in order to determine permissible prices.
These categories include Section 102 "new natural gas" and gas from certain new
offshore reservoirs, Section 104 "interstate gas", Section 106 gas sold under
"rollover contracts", Section 107 "high cost gas", and Section 109 "other gas".
Certain of these categories require a well category determination. For such
categories, the NGPA delegates to the appropriate federal agencies, subject to
review by the FERC, the determination of the applicable category. Factors
considered in determining classification include the location of a well, when
drilling began, when it was completed, the surface distance from existing
production, the depth at which production is established, whether the well is
onshore or offshore, the date of commencement or renewal of any underlying gas
sales agreement, the date of commitment of the underlying gas reserves to
interstate commerce and the rate of productivity of the well. All prices
established under the NGPA are generally allowed to increase monthly based on an
inflation factor, and an additional growth factor applies to Section 102 gas.
Generally, none of the NGPA prices can be collected without the requisite
contractual authority.
The NGPA was designed to effect deregulation of the sales price for certain
categories of natural gas. For some categories of natural gas, the sales price
was deregulated prior to January 1, 1985; the prices of certain other categories
of natural gas were deregulated on January 1, 1985. Other categories of gas have
subsequently been deregulated as described below pursuant to the Natural Gas
Decontrol Act of 1989.
With respect to certain gas committed or dedicated to interstate commerce
prior to the enactment of the NGPA, producers who sell gas for resale in
interstate commerce must obtain certificates of public convenience and necessity
before commencing such sales, make certain filings with respect to the prices at
which such sales are made and secure approval prior to abandonment of service
once it is commenced.
In September 1988, the NGPA was amended to repeal the requirement of a
minimum 15-year term on certain gas contracts. The NGPA had previously imposed a
minimum 15-year term on new contracts for new Outer Continental Shelf ("OCS")
gas. This requirement was imposed in connection with the termination of the
Natural Gas Act regulation of such new OCS gas as a substitute for the Natural
Gas Act requirement for FERC approval of abandonment. Since 1978, changes in the
gas markets, especially the development of an active spot market and
deliverability surplus, caused significant changes in gas contracting practices.
Whereas prior to the enactment of the NGPA, long-
23
term contracts were standard, current purchasing patterns involve short-term
contracts containing flexible pricing terms. As a consequence, the 15-year
contract term requirement became an impediment to marketing of competitively
priced new OCS gas. Repeal of this prohibition brings the NGPA into conformance
with current contracting practice and the reality of the market.
Another NGPA section which was terminated related to new gas which was
"committed or dedicated to interstate commerce" prior to enactment of the NGPA.
A limited form of supply security had been provided to purchasers whose
contracts had expired by giving them a right of preferential purchase. In Order
No. 490, the FERC granted blanket abandonment for gas which remained subject to
National Gas Act regulation. As a consequence, some new gas which under the NGPA
was intended to have less regulation was actually subject to greater regulatory
burdens than old interstate gas which the NGPA left subject to Natural Gas Act
regulations. Therefore, Congress repealed the NGPA section allowing for the
preferential right of purchase of this gas.
In July 1989, the Natural Gas Decontrol Act of 1989 was enacted, which
provides for complete price decontrol of first sales of gas as of January 1993
through repealing Title I of the NGPA. Prior to January 1993, this Act provides
for: (1) immediate decontrol of gas to which no first sales contract applied on
date of enactment; (2) decontrol of gas under existing gas contracts as the
contracts expire or are terminated; (3) decontrol in May 1991 of gas covered by
sales contracts on the date of enactment and produced from wells spudded after
the date of enactment and (4) decontrol of gas under contracts renegotiated
after March 23, 1989 to provide that maximum lawful prices will not apply.
Commencing in late 1985 and early 1986, the FERC issued a series of rules
and orders (Order No. 436, Order No. 500, and related orders) that made sweeping
changes in its regulations governing the transportation and marketing of natural
gas supplies. Among other things, the new regulations (i) require interstate
pipelines that elect to transport gas for others under self-implementing
authority to provide transportation services to all shippers on a
non-discriminatory basis; (ii) permit each existing firm sales customer of such
pipelines to modify over at least a five-year period its existing purchase
obligations; (iii) establish a complicated procedure to permit pipelines that
transport gas under the regulations to credit the volumes transported on a
volumetric basis against take-or-pay obligations under contracts in existence on
June 23, 1987; and (iv) establish guidelines that permit pipelines to recover
from customers all or a portion of payments made to producers in settlement of
take-or-pay contract disputes.
On August 24, 1990, the D.C. Circuit upheld most aspects of the final rule
in the Order No. 500 series. Only issues regarding pregranted abandonment of
converted transportation services and double-crediting were remanded by the
Court to the FERC for further action. The pregranted abandonment issue is
addressed in Order No. 636. With respect to the double crediting issue, on April
4, 1991, the FERC issued Order 500-K in which it ruled that its take-or-pay
crediting regulations did not result in producers providing double take-or-pay
credits in certain circumstances. Although the Working Interest Owners are
unable to predict the consequences of the new rules, the Working Interest Owners
believe such rules could have a significant effect on all segments of the
natural gas industry. Many of the principal features of the final rule are
voluntary. Although the new rules do not directly regulate gas producers such as
the Working Interest Owners, the FERC has stated that the rules are intended
primarily to foster increased competition in the natural gas industry and to
allow more accurate price signals to be transmitted from consumers to producers,
such as the Working Interest Owners.
On April 8, 1992, the FERC issued Order No. 636, which implemented a major
restructuring of interstate pipeline operations in order to enhance the
competitive structure of the pipeline industry and maximize the benefits of a
competitive wellhead market resulting from wellhead price decontrols. Order No.
636 requires, among other things, that all interstate pipelines eliminate their
bundled city gate sales services by unbundling their sales services from their
transportation services. Unbundled sales customers have been given the right to
reduce their firm sales entitlements in whole or in part, thereby enabling such
customers to negotiate with other parties for long-term supplies. Order No. 636
also requires that open access pipelines provide transportation services
comparable in quality for all gas supplies, whether purchased from the pipeline
or elsewhere. The FERC would require that operational terms and conditions
imposed on a pipelines transportation service result in nondiscriminatory
treatment for pipeline sales gas and third party sales gas. In this way,
pipelines, producers,
24
marketers and all other merchants of gas would be able to compete on an equal
footing. The stated purpose of Order No. 636 is to create a national gas
market where a buyer can reach many sellers by meaningful access to the
pipeline transportation grid. On August 3, 1992, the FERC issued Order No.
636-A, which largely reaffirmed Order No. 636 and denied stay of the
implementation of the new rule pending judicial review. On November 27, 1992,
the FERC issued Order No. 636-B, which uniformly upheld the regulations
adopted in Order Nos. 636 and 636-A. As a result of these orders, individual
so-called "restructuring" proceedings were established for each interstate
pipeline to develop particularized features and procedures for each pipeline's
system to implement Order No. 636. Order No. 636 is the subject of appeals to
the United States Court of Appeals for the D.C. Circuit and to additional
action by the FERC.
On December 9, 1988, the FERC issued Order No. 509 which provides every
jurisdictional interstate natural gas pipeline that transports gas on or across
the OCS with a blanket certificate authorizing and requiring nondiscriminatory
transportation of natural gas on behalf of others, and requires every OCS
pipeline to file tariffs to implement that blanket certificate authorization.
The service performed under the blanket certificate includes both firm and
interruptible transportation service and OCS pipelines must, pursuant to the
blanket certificate, provide open and nondiscriminatory access for both owner
and nonowner shippers. Order No. 509 also provided that if an OCS pipeline
received a request for service, the pipeline would be required to allocate
capacity pro rata in order to provide the requested service. Order No. 509 will
facilitate the transportation and marketability of OCS gas. On August 14, 1992,
the D.C. Circuit remanded the final rule back to the FERC for further
consideration as to whether the FERC has authority to require a pipeline to file
to abandon service to a shipper prior to the termination of the underlying
contract and to charge a replacement shipper the generally applicable rate, not
the old shipper's rate. On October 4, 1993, the FERC issued Order No. 559 in
which the FERC (1) addressed the issues raised by the Court's August 14, 1992
order and (2) amended certain regulations and removed other regulations
promulgated in Order No. 509. Specifically, the Commission removed the
regulations concerning the capacity allocation program established in Order No.
509 and the regulation providing for abandonment authority. The capacity
allocation regulations promulgated in Order No. 509 have been subsumed by the
Order No. 636 capacity release program.
In September of 1991, the FERC issued a final rule in Order 537 in which it
amended its regulations for the transportation of natural gas pursuant to
Section 311 of the NGPA. Generally, the final rule requires that for interstate
pipeline transportation under Section 311, the "on behalf of" entity (interstate
pipeline or local distribution company) must either (1) have physical custody of
or transport the gas at some point during the transaction or (2) hold title to
the gas at some point during the transaction for a purpose related to its status
as an intrastate pipeline or an LDC. In addition, the final rule authorizes
Section 311 transportation services by interstate pipelines for end users
located in the service areas of non-transporting, non-title holding intrastate
pipelines and LDC's that certify that the interstate pipeline's transportation
is on their behalf. On September 21, 1992, the FERC issued Order No. 537-A which
largely upheld the regulations adopted in Order No. 537. On January 14, 1993,
the FERC issued Order No. 537-B which clarified Order No. 537-A. On April 25,
1994, the United States Court of Appeals for the D.C. Circuit upheld Order Nos.
537, 537-A and 537-B.
On October 28, 1993, the Commission issued a Notice of Public Conference
indicating its intent to convene a public conference to explore, INTER ALIA, (1)
the structure and operation of natural gas gathering markets, (2) the effects of
current FERC policy regarding gathering and the need either to maintain or
depart from current policy, and (3) the extent to which the Commission should
exercise its Natural Gas Act rate and tariff jurisdiction pursuant to Sections 4
and 5 of the Natural Gas Act over the rates, terms and conditions for gathering
services performed by interstate pipelines and their affiliates. Other issues
explored by the Commission at the February 24, 1994 public conference include
production area transportation rates and rate design and the proper treatment of
interstate pipeline profits from the sale of gathering systems to an affiliate
or non-related entity. It is not known at this time what gathering and
production-area policies the FERC will adopt as a result of the public
conference.
25
On February 28, 1996, the FERC issued a Statement of Policy regarding the
application of its jurisdiction under the NGA and the Outer Continental Shelf
Lands Act over new natural gas facilities and services on the Outer Continental
Shelf ("OCS"). In its Policy Statement, the FERC concluded that it will retain
its existing primary function test to determine whether particular facilities on
the OCS constitute gathering facilities exempt from the FERC's NGA jurisdiction.
However, the FERC added a new factor to its primary function test for facilities
that are designed to collect gas produced in water depths of 200 meters or more.
Such facilities now will be presumed to qualify as gathering facilities up to
the point or points of potential connection with the interstate pipeline grid.
Downstream of that point, the facilities will be evaluated under the existing
primary function test. Existing interstate pipelines and gathering facilities
would retain their present status barring some change in circumstances.
The Trust cannot predict the full effect that continuing judicial,
legislative and regulatory involvement in various natural gas issues will have
on prices, markets or terms of sale of natural gas.
ENVIRONMENTAL REGULATIONS
GENERAL
The Working Interest Owners' oil and gas activities on the Royalty
Properties are subject to existing and evolving federal, state and local
environmental laws and regulations. The Working Interest Owners have advised the
Trust that they believe that their operations and facilities are in general
compliance with applicable health, safety, and environmental laws and
regulations that have taken effect at the federal, state and local levels. In
addition, events in recent years have heightened environmental concerns about
the oil and gas industry generally, and about offshore operations in particular.
The Working Interest Owners' operation of federal offshore oil and gas leases is
subject to extensive governmental regulation, including regulations that may, in
certain circumstances, impose absolute liability upon lessees for cost of
removal of pollution and for pollution damages resulting from their operations,
and require lessees to suspend or cease operations in the affected areas. For
instance, the U.S. Coast Guard has promulgated interim regulations concerning
financial responsibility for vessels, including mobile offshore drilling units
("MODUs"), under the Oil Pollution Act of 1990 and CERCLA. These provisions
require owners and operators of vessels to establish and maintain evidence of
financial responsibility sufficient to meet their potential liability for
discharges or threatened discharges of oil or hazardous substances. Similar
financial responsibility requirements for offshore operations are contained in a
bill currently before Congress and in regulations proposed by the Minerals
Management Service. Although the Working Interest Owners have advised the Trust
that current environmental regulation has had no material adverse effect on the
Working Interest Owners' present method of operations, the impact of the
recently adopted and proposed regulatory changes, and of future environmental
regulatory developments such as stricter environmental regulation and
enforcement policies, cannot presently be quantified.
The Working Interest Owners' operations are subject to regulation,
principally under the following federal statutes, along with their analogous
state statutes.
WATER
The Federal Water Pollution Control Act of 1972, as amended, and the Oil
Pollution Act of 1990 impose certain liabilities and penalties upon persons and
entities, such as the Working Interest Owners, for any discharges of petroleum
products in reportable quantities, for the costs of removing an oil spill, and
for natural resource damages. State laws for the control of water pollution also
provide varying civil and criminal penalties and liabilities in the case of a
release of petroleum or its derivatives in surface waters. Within the next one
to three years, both the Texas and Louisiana state water discharge regulations
and the federal NPDES permits may prohibit the discharge of produced water, sand
and other substances related to the oil and gas industry to coastal waters of
Louisiana and Texas. Although the cost to reformat operations to comply with
these zero discharge mandates under federal or state law may be significant, the
entire industry will experience similar costs. The Working Interest Owners
believe that these costs will not have a material adverse impact on these
operations. Further, the Coastal Zone Management Act authorizes state
implementation and development of programs to restore and protect coastal waters
by managing non-point source pollution. An imposition of such
26
liabilities on the Working Interest Owners could result in increased operating
expenses to the Working Interest Owners on the Royalty Properties.
AIR EMISSIONS
Amendments to the federal Clean Air Act were enacted in late 1990 and
require most industrial operations in the United States, including offshore
operations, to incur future capital expenditures in the next several years for
air emission control equipment in connection with maintaining and obtaining
operating permits and approvals addressing other air emission related issues.
The Environmental Protection Agency ("EPA") and state environmental agencies
have been developing regulations to implement these requirements. Some of the
Working Interest Owners' facilities are included within the categories of
hazardous air pollutant sources which will be affected by these regulations and
these regulations could make operation of the Royalty Properties more costly.
SOLID WASTE
The Working Interest Owners' operations may generate wastes that are
subject to the federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The EPA has limited disposal options for certain
hazardous wastes and may adopt more stringent disposal standards for
nonhazardous wastes. Furthermore, it is possible that some wastes that are
currently classified as nonhazardous, perhaps including wastes generated during
drilling and production operations, may in the future be designated as
"hazardous wastes". Such changes in the regulations would result in more
rigorous and costly disposal requirements which could result in increased
operating expenses on the Royalty Properties.
NORM
Oil and gas exploration and production activities have been identified as
generators of low-level naturally-occurring radioactive materials ("NORM"). The
generation, handling and disposal of NORM in the course of offshore oil and gas
exploration and production activities is currently regulated in federal and
state waters. These regulations could result in an increase in operating
expenses on the Royalty Properties.
SUPERFUND
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to the fault or the legality of the original conduct, on certain classes of
persons that contributed to the release of a "hazardous substance" into the
environment. These persons include the current or previous owner and operator of
a facility and companies that disposed or arranged for the disposal of the
hazardous substance found at a facility. CERCLA also authorizes the EPA and, in
some cases, private parties to take actions in response to threats to the public
health or the environment and to seek recovery from such responsible classes of
persons of the costs, which can be substantial, of such action. Although
"petroleum" is excluded from CERCLA's definition of a "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.
27
ITEM 2. PROPERTIES.
Reference is made to Item I 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 1995.
28
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Units are traded on the National Association of Securities Dealers
Automated Quotation System ("NASDAQ") Small-Cap Market under the symbol TELOZ.
The high and low sales price as reported by NASDAQ for each quarter for the
years ended December 31, 1995 and 1994, were as follows:
<TABLE>
<CAPTION>
1995 1994
-------------------- --------------------
SALES SALES
-------------------- --------------------
QUARTER HIGH LOW HIGH LOW
- ------------------------------------------------------------------ --------- --------- --------- ---------
<S> <C> <C> <C> <C>
First............................................................. $ 1.500 $ 1.000 $ 2.125 $ 0.875
Second............................................................ $ 1.250 $ 0.938 $ 1.750 $ 1.000
Third............................................................. $ 1.125 $ 0.938 $ 1.750 $ 1.250
Fourth............................................................ $ 1.188 $ 0.875 $ 2.000 $ 1.000
</TABLE>
The distributions paid each quarter for the years ended December 31, 1995
and 1994, were as follows:
<TABLE>
<CAPTION>
1995 1994
------------- -------------
DISTRIBUTION DISTRIBUTION
QUARTER PAID PAID
- -------------------------------------------------------------------- ------------- -------------
<S> <C> <C>
First............................................................... $ .014441 $ .296359
Second.............................................................. $ .039029 $ .101174
Third............................................................... $ .058317 $ .105312
Fourth.............................................................. $ .017609 $ .055044
</TABLE>
At April 3, 1996, the 4,751,510 Units outstanding were held by 3,047 Unit
holders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
1995 1994 1993 1992 1991
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Royalty income........................ $ 1,383,458 $ 3,435,312 $ 2,260,737 $ 1,157,064 $ 3,364,686
Distributable income.................. $ 614,836 $ 2,650,823 $ 1,668,678 $ 561,826 $ 2,732,916
Distributions per Unit................ $ .129396 $ .557889 $ .351020 $ .118240 $ .575200
Total assets at year end.............. $ 2,333,224 $ 2,412,692 $ 2,809,076 $ 2,942,606 $ 3,449,454
</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 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. At
December 31, 1991, a cash reserve of $120,000 had been established for future
Trust administrative expenses. During 1992 and 1993, in anticipation of future
periods when the cash received from the
29
Royalty may not be sufficient for payment of Trust expenses, the reserve for
future Trust administrative expenses was increased each quarter by an amount
equal to the difference between $150,000 and the amount of the Trust's general
and administrative expenses for such quarter. In March 1994, the Trust
determined, in accordance with the Trust Agreement, to begin further increasing
the Trust's cash reserve each quarter by an amount equal to the difference
between $200,000 and the amount of the Trust's general and administrative
expenses for such quarter. During 1993, 1994 and 1995, the aggregate amount of
cash reserved by the Trust was $151,336, $347,638 and $370,258 respectively,
bringing the total amount of the Trust's cash reserve at December 31, 1995 to
$1,177,932.
OPERATIONS
YEARS 1995 AND 1994
Royalty income decreased 60% from $3,435,312 in 1994 to $1,383,458 in 1995
primarily due to a net deposit into the Special Cost Escrow Account in 1995 as
compared to the net release made from the Special Cost Escrow Account in 1994.
The Trust's share of the net amount released from the Special Cost Escrow
Account during 1994 was approximately $1,711,000. In 1995, the Trust's share of
the net amount deposited into the Special Cost Escrow Account was approximately
$207,000. See "Special Cost Escrow Account" 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 32% in 1995 as compared to 1994. Gas
volumes sold decreased approximately 19% from 2,300,991 Mcf in 1994 to 1,863,531
Mcf in 1995, and the average price received for natural gas decreased from $2.04
per Mcf in 1994 to $1.66 per Mcf in 1995. The decrease in volumes was primarily
attributable to the C-10 well being watered out and the C-4 well being sanded in
on the Ship Shoal 182/183 property during portions of the second, third, and
fourth quarters of 1995 and the continued natural production decline as the
Royalty Properties approach the end of their productive lives.
Chevron has advised the Trust that as of October 31, 1995 approximately
265,300 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 $306,800 in 1995 related to such imbalance. Chevron has
advised the Trust that sufficient gas reserves exist on Eugene Island 339 for
underproduced parties to recoup their share of the gas imbalance on that
property.
During 1994, Pennzoil, the Working Interest Owner on the Eugene Island 348
property, settled the 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 $5,000 and $150,000 was recovered from the
Trust by the Working Interest Owner during 1994 and 1995, respectively, and the
remainder will be subject to recovery from the Trust in future periods, in
accordance with the Conveyance. The Working Interest Owner has advised the Trust
that future Royalty income attributable to all of the Royalty Properties owned
by Pennzoil will be used to offset the Trust's share of such settlement amounts.
Based on current production, prices and expenses for the Royalty Properties
owned by Pennzoil, it is estimated that Royalty income attributable to such
properties will be retained by Pennzoil for the remaining life of the Trust. The
Trust does not anticipate that retention of such Royalty income by Pennzoil will
have a material effect on the Trust's Royalty income as a whole.
30
CRUDE OIL AND CONDENSATE
Crude oil revenues increased slightly in 1995 compared to the previous year
due to an increase in the average price received from $14.41 per barrel in 1994
to $16.10 per barrel in 1995. This increase in average price received was
partially offset by a decrease in crude oil volumes from 548,669 barrels in 1994
to 501,501 barrels in 1995. This decrease in volumes was primarily attributable
to the continued natural production decline as the properties grow nearer to the
end of their productive lives.
OPERATING AND CAPITAL EXPENDITURES
Operating expenses, excluding the gas imbalance settlement discussed above,
decreased from $5,233,943 in 1994 to $3,503,644 in 1995 due primarily to
expenses incurred in 1994 in connection with a workover on the Eugene Island 339
B-13 well and workovers on four West Cameron 643 wells. Capital expenditures
increased from $184,017 in 1994 to $839,964 in 1995 due primarily to expenses
incurred in the first quarter of 1995 in connection with the installation of a
Supervisory Control and Data Acquisition system on the West Cameron 643 property
and the B-3 well workover performed on the West Cameron 643 property in the
second quarter of 1995.
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
$112,500 in 1995, serves to reduce the Trust's share of allocated production
costs. Special Cost Escrow funds will generally be utilized to pay Special Costs
to the extent there are not adequate current net proceeds to pay such costs.
Special Costs that have been paid are no longer included in the Special Cost
Escrow calculation. Deposits to the Special Cost Escrow Account will generally
be made when the balance in the Special Cost Escrow Account is less than 125% of
future Special Costs and there is a Net Revenues Shortfall (a calculation of the
excess of estimated future costs over estimated future net revenues pursuant to
a formula contained in the Conveyance). When there is not a Net Revenues
Shortfall, amounts in the Special Cost Escrow Account will generally be
released, to the extent that Special Costs have been 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 1994, the Working Interest Owners released a net amount of approximately
$1,711,000 from the Special Cost Escrow Account primarily as a result of a
decrease in future estimated Special Costs of the Royalty Properties. This
decrease was due in part to a decrease in estimated abandonment costs as a
result of technological improvements in abandonment procedures utilized by the
Working Interest Owners and a decrease in planned capital projects.
In 1995, the Working Interest Owners deposited a net amount of
approximately $207,000 into the Special Cost Escrow Account. The deposit was
primarily a result of an increase in the current estimate of projected capital
expenditures on the Royalty Properties. As of December 31, 1995, approximately
$2,572,000 remained in the Special Cost Escrow Account.
In the first quarter of 1996, the current escrow balance, current estimates
of aggregate future capital expenditures, aggregate future abandonment costs,
aggregate future production costs, aggregate future net revenues and current net
proceeds resulted in a deposit of funds into the Special Cost Escrow Account
amounting to $982,600. The deposit was primarily a result of an increase in the
current
31
estimate of projected capital expenditures, production costs and abandonment
costs of the Royalty Properties. See "-- Recent Developments" below.
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 1995 operations as compared to 1994 on the
principal Royalty Properties. As discussed above under "Description of the
Trust" in Item 1 of this Form 10-K, Net Proceeds of an individual Royalty
Property are determined by deducting Production Costs from the Gross Proceeds of
such property. Adjusted Net Proceeds is the Net Proceeds amount exclusive of the
cash reserve for the future costs to be incurred by the Working Interest Owners
to plug and abandon wells, dismantle and remove platforms, pipelines and other
production facilities from the Royalty Properties, for future drilling projects
and other estimated future capital expenditures on the Royalty Properties and
the interest earned on the costs escrowed.
<TABLE>
<CAPTION>
PERCENT OF TRUST
ADJUSTED NET
PROCEEDS
CONTRIBUTED IN
LEASE NAME 1995 SUMMARY DATA
- ------------------------------------- ------------------- -----------------------------------------------------------
<S> <C> <C>
Ship Shoal 182/183................... 49% A 17% decrease in crude oil production from 307,347 barrels
in 1994 to 253,747 barrels in 1995 and a 12% increase in
crude oil average prices from $14.41 per barrel in 1994 to
$16.17 per barrel in 1995 resulted in a 7% decrease in
crude oil revenues from $4,430,382 in 1994 to $4,104,147 in
1995. The decrease in crude oil production was primarily
due to a continued natural production decline. Gas revenues
decreased 66% from $1,388,268 in 1994 to $471,989 in 1995
due primarily to a decrease in volumes. Gas volumes
decreased from 677,365 Mcf in 1994 to 269,861 Mcf in 1995
due primarily to the C-10 well being watered out and the
C-4 well being sanded in during portions of the second,
third and fourth quarters of 1995 and the continued natural
production decline. The C-10 well resumed production in May
1995. In addition there was a decrease in the average
natural gas sales price from $2.08 per Mcf in 1994 to $1.74
per Mcf in 1995.
Capital expenditures decreased from $132,210 in 1994 to
$34,137 in 1995 due primarily to a compressor restaging and
a new compressor engine in 1994.
The Working Interest Owner has advised the Trust that
approximately 61,000 Mcf have been overtaken by the Working
Interest Owner from this property. The Trust's share of
this overtake position is approximately 15,250 Mcf.
Accordingly, gas revenues from this property may be reduced
in future periods while underproduced parties recover their
share of the gas imbalance.
In January 1996, the Working Interest Owner drilled the F-2
delineation gas well on this property. The completed well
cost is estimated at approximately $2.0 million ($492,000
net to the Trust). The
32
Working Interest Owner recently advised the Trust that in
late March 1996, the F-2 well was producing approximately
150 Mcf per day. The well is currently shut in for repairs.
In addition, the Working Interest Owner has advised the
Trust that it plans to drill two development oil wells on
this property in May 1996 at an estimated cost of
approximately $7.6 million ($1.9 million net to the Trust.)
See " -- Recent Developments" below.
Eugene Island 339.................... 48% Crude oil revenues increased 15% from $3,304,344 in 1994 to
$3,800,360 in 1995 primarily due to an increase in the
average price received from $14.35 per barrel in 1994 to
$16.03 per barrel in 1995. In addition, there was an
increase in volumes from 230,273 barrels in 1994 to 237,015
barrels in 1995. Gas revenues decreased 16% from $1,192,797
in 1994 to $1,005,792 in 1995 primarily due to a decrease
in gas volumes from 587,820 Mcf in 1994 to 546,316 Mcf in
1995. The decrease in gas volumes was primarily due to
reduced takes in an effort to reduce an overbalance
position and the continued natural production decline. In
addition, the average natural gas sales price decreased
from $2.10 per Mcf in 1994 to $1.79 per Mcf in 1995.
As discussed under "Description of the Royalty
Properties-Reserves," the Working Interest Owner has
advised the Trust that as of October 31, 1995 there was an
overtake imbalance position of approximately 265,300 Mcf
(66,300 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.
Operating expenses decreased from $2,406,872 in 1994 to
$1,567,702 in 1995 primarily due to expenses incurred in
1994 in connection with the well workover on the B-13 well.
In 1994, the Working Interest Owner purchased a three
dimensional seismic survey of this property. The survey
continues to be evaluated by the Working Interest Owner.
The Working Interest Owner has advised the Trust that they
will pursue drilling on this property in 1997 if drilling
on non-trust properties in 1996 is successful.
West Cameron 643..................... 0% Natural gas revenues decreased 48% from $1,766,407 in 1994
to $910,018 in 1995 primarily due to a decrease in volumes
from 890,692 Mcf in 1994 to 574,763 Mcf in 1995. The
decrease in gas volumes was due to decreased takes and a
continued natural production decline. The decrease in takes
by the Working Interest Owner was primarily due to a
33
decrease in the average price received for natural gas from
$1.98 per Mcf in 1994 to $1.58 per Mcf in 1995.
Operating expenses decreased from $1,088,165 in 1994 to
$349,890 in 1995 due primarily to expenses incurred in 1994
in connection with workovers on the A-1, A-2, A-4 and A-7
wells. The Working Interest Owner has advised the Trust
that the six workovers on the A-2, A-6, A-9, A-10, A-16 and
A-17 wells to be performed in the fourth quarter of 1995
were delayed until first and second quarters of 1996.
The estimated cost of the six workovers is $1,579,600
($394,900 net to the Trust).
Capital expenditures increased from $3,769 in 1994 to
$680,150 in 1995 due primarily to a Supervisory Control and
Data Acquisition system installation on the property in the
first quarter of 1995 and a workover on the B-3 well in the
second quarter of 1995.
The Working Interest Owner has advised the Trust that in
the second quarter of 1996 three wells were drilled on this
property at an aggregate cost of $5.6 million ($1.4 million
net to the Trust). The Working Interest Owner has further
advised the Trust that as a result of this drilling, its
estimates of proved reserves on this property have
increased by approximately 3,000 barrels of crude oil and
condensate (750 barrels net to the Trust) and 2,400,000 Mcf
of gas (600,000 Mcf net to the Trust).
</TABLE>
YEARS 1994 AND 1993
Royalty income increased 52% from $2,260,737 in 1993 to $3,435,312 in 1994
primarily due to the net release from the Special Cost Escrow Account in 1994 as
compared to the deposit made to the Special Cost Escrow Account in 1993. The
Trust's share of the amount deposited into the Special Cost Escrow Account
during 1993 was approximately $700,000. The deposit was due primarily to an
increase in future estimated production costs in connection with wells drilled
in 1992 and other expenditures projected by the Working Interest Owners. In
1994, the Trust's share of the net amount released from the Special Cost Escrow
Account was approximately $1,711,000. The release was primarily a result of a
decrease in future estimated Special Costs.
Gas revenues decreased approximately 42% in 1994 as compared to 1993. Gas
takes decreased approximately 35% from 3,539,441 Mcf in 1993 to 2,300,991 Mcf in
1994, and the average price received for natural gas decreased from $2.25 per
Mcf in 1993 to $2.04 per Mcf in 1994. The decrease in volumes was primarily
attributable to the continued natural production decline as the properties
approach the end of their productive lives.
Crude oil revenues decreased approximately 24% in 1994 compared to the
previous year due in part to a decrease in the average price received from
$16.94 per barrel in 1993 to $14.41 per barrel in 1994. In addition, there was a
10% decrease in crude oil volumes from 612,691 barrels in 1993 to 548,669
barrels in 1994. This decrease in volumes was primarily attributable to the
continued natural production decline as the properties grow nearer to the end of
their productive lives.
Operating expenses, excluding the gas imbalance settlement on the Eugene
Island 348 property, decreased from $5,643,338 in 1993 to $5,233,943 in 1994. In
addition, capital expenditures decreased from $586,259 in 1993 to $184,017 in
1994. The decrease in the aggregate operating and capital
34
expenses was primarily due to reduced expenditures in connection with the
completion of workovers on the Eugene Island 339 property in 1993, as discussed
elsewhere herein.
SUMMARY BY PROPERTY.
Listed below is a summary of 1994 operations as compared to 1993 on the
principal Royalty Properties. Volumes and dollar amounts discussed below
represent amounts recorded by the Working Interest Owners unless noted
otherwise. As discussed above under "Description of the Trust" in Item 1 of this
Form 10-K, Net Proceeds of an individual Royalty Property are determined by
deducting Production Costs from the Gross Proceeds of such property. Adjusted
Net Proceeds is the Net Proceeds amount exclusive of the cash reserve for the
future costs to be incurred by the Working Interest Owners to plug and abandon
wells, dismantle and remove platforms, pipelines and other production facilities
from the Royalty Properties, for future drilling projects and other estimated
future capital expenditures on the Royalty Properties and the interest earned on
the costs escrowed. The percentages set forth under the column entitled "Percent
of Trust Adjusted Net Proceeds Contributed in 1994" reported in this section
excludes the gas imbalance settlement on the Eugene Island 348 property.
<TABLE>
<CAPTION>
PERCENT OF TRUST
ADJUSTED NET
PROCEEDS
CONTRIBUTED IN
LEASE NAME 1994 SUMMARY DATA
- ------------------------------------- ------------------- -----------------------------------------------------------
<S> <C> <C> <C>
Ship Shoal 182/183................... 63% A 20% decrease in crude oil production from 382,094 barrels
in 1993 to 307,347 barrels in 1994 and a 15% decrease in
crude oil average prices from $16.91 per barrel in 1993 to
$14.41 per barrel in 1994 resulted in a 31% decrease in
crude oil revenues from $6,460,843 in 1993 to $4,430,382 in
1994. The decrease in crude oil production was primarily
due to a continued natural decline in the productive
capacity of the property. Gas revenues decreased 50% from
$2,774,007 in 1993 to $1,388,268 in 1994 due primarily to a
decrease in volumes. Gas volumes decreased from 1,209,342
Mcf in 1993 to 677,365 Mcf in 1994 due primarily to a
continued natural decline in the productive capacity and
decreased takes on this property. In addition there was a
decrease in the average natural gas sales price from $2.32
per Mcf in 1993 to $2.08 per Mcf in 1994.
Operating expenses decreased from $1,492,484 in 1993 to
$1,342,226 in 1994 due primarily to a reduction in facility
usage costs and transportation expense.
Capital expenditures increased from $5,123 in 1993 to
$132,210 in 1994 due primarily to a compressor restaging
and a new compressor engine in 1994.
Eugene Island 339.................... 28% Crude oil revenues decreased 9% from $3,645,893 in 1993 to
$3,304,344 in 1994 primarily due to a decrease in the
average price received from $16.94 per barrel in 1993 to
$14.35 per barrel in 1994. The decrease in the average
price received for crude oil and condensate was offset
partially by an increase in volumes from 215,203 barrels in
1993 to 230,273 barrels in 1994. Gas revenues decreased 49%
from $2,324,485 in 1993 to $1,192,797 in 1994 primarily due
to a decrease in gas volumes from 990,034 Mcf
35
in 1993 to 587,820 Mcf in 1994. The decrease in gas volumes
was primarily due to the continued natural decline in the
productive capacity of the property. In addition, the
average natural gas sales price decreased from $2.23 per
Mcf in 1993 to $2.10 per Mcf in 1994.
Operating expenses decreased from $2,600,698 in 1993 to
$2,406,872 in 1994.
Capital expenditures decreased from $460,546 in 1993 to
$13,665 in 1994 due primarily to expenses incurred in 1993
in connection with the B-13 well workover and the B-2 side
track drilling in 1992.
West Cameron 643..................... 9% Natural gas revenues decreased 33% from $2,628,656 in 1993
to $1,766,407 in 1994 primarily as a result of a decrease
in volumes from 1,202,673 Mcf in 1993 to 890,692 Mcf in
1994. The decrease in gas volumes was due in part to the
A-2 well being "sanded up" and shut in beginning the fourth
quarter of 1993 and due in part to the continued natural
production decline. In addition, there was a decrease in
the average price received for natural gas from $2.19 per
Mcf in 1993 to $1.98 per Mcf in 1994. Operating expenses
decreased from $1,187,704 in 1993 to $1,088,165 in 1994.
</TABLE>
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)
----------------------------------------
1995 1994 1993
---------- ---------- ----------
<S> <C> <C> <C>
Crude oil and condensate (bbls)............... 501,501 548,669 612,691
Natural gas and gas products (Mcf)............ 1,863,531 2,300,991 3,539,441
Crude oil and condensate average price, per
bbl......................................... $ 16.10 $ 14.41 $ 16.94
Natural gas average price, per Mcf (excluding
gas products)............................... $ 1.66 $ 2.04 $ 2.25
Crude oil and condensate revenues............. $8,075,761 $ 7,906,903 $10,377,166
Natural gas and gas products revenues......... 3,152,901 4,648,856 8,041,282
Production expenses........................... (4,026,706) (5,473,106) (5,988,507)
Capital expenditures.......................... (839,964) (184,017) (586,259)
(Provision for) Refund of escrowed special
costs....................................... (827,608) 6,843,988 (2,799,828)
---------- ---------- ----------
NET PROCEEDS.................................. $5,534,384 $13,742,624 $ 9,043,854
Royalty interest.............................. X25% X25% X25%
---------- ---------- ----------
Partnership share............................. 1,383,596 3,435,656 2,260,963
Trust interest................................ X99.99% X99.99% X99.99%
---------- ---------- ----------
Trust share................................... $1,383,458 $ 3,435,312 $ 2,260,737
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
36
- ------------
(1) Amounts represent actual production for the twelve month period ending on
October 31 of each year, respectively.
RECENT DEVELOPMENTS
In January 1996, Chevron advised the Trust that Chevron had drilled the F-2
delineation gas well on the Ship Shoal 182/183 property and that Chevron intends
to drill two development oil wells on the Ship Shoal 182/183 property in May
1996. Chevron recently advised the Trust that in late March 1996 the F-2 well
was producing approximately 150 Mcf per day. The well is currently shut in for
repairs. The completed well cost of the F-2 well is estimated at approximately
$2.0 million ($492,000 net to the Trust). The total completed well cost of the
two planned development oil wells is estimated at approximately $7.6 million
($1.9 million net to the Trust). As a result of the projected capital
expenditures, production costs and abandonment costs in connection with the Ship
Shoal 182/183 drilling, there was a Special Cost Escrow deposit for the first
quarter of 1996 in the amount of $982,600. As a result of such Special Cost
Escrow deposit, there was no royalty income for the first quarter of 1996.
Chevron has advised the Trust that the projected capital expenditures,
production costs and abandonment costs in connection with the Ship Shoal 182/183
drilling could result in additional deposits to the Special Cost Escrow Account
for subsequent quarters in 1996. Such deposits, if made, could result in a
significant reduction in royalty income in the periods in which such deposits
are made, including the possibility that no royalty income would be received in
such periods.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
37
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Trustees and Unit Holders of TEL Offshore Trust:
We have audited the accompanying statements of assets, liabilities and
trust corpus of TEL Offshore Trust as of December 31, 1995 and 1994, and the
related statements of distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 1995. These financial
statements are the responsibility of the Trustees. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
These financial statements were prepared on the basis of accounting
described in Note 3 to the financial statements, which is 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, 1995 and 1994, and its distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 1995, on the comprehensive basis of accounting described in Note 3.
ARTHUR ANDERSEN LLP
Houston, Texas
April 10, 1996
38
TEL OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1995 1994 1993
------------- ------------- -------------
<S> <C> <C> <C>
Royalty income................................................ $ 1,383,458 $ 3,435,312 $ 2,260,737
Interest income............................................... 31,378 15,511 7,941
------------- ------------- -------------
1,414,836 3,450,823 2,268,678
General and administrative expenses........................... (429,742) (452,362) (448,664)
Increase in reserve for future Trust expenses................. (370,258) (347,638) (151,336)
------------- ------------- -------------
Distributable income.......................................... $ 614,836 $ 2,650,823 $ 1,668,678
------------- ------------- -------------
------------- ------------- -------------
Distributions per Unit (4,751,510 Units)...................... $ .129396 $ .557889 $ .351020
------------- ------------- -------------
------------- ------------- -------------
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1995 1994
------------- -------------
ASSETS
<S> <C> <C>
Cash and cash equivalents........................................................ $ 1,261,606 $ 1,069,217
Net overriding royalty interest in oil and gas properties, net of accumulated
amortization of $27,196,037 and $26,924,180, at December 31, 1995 and 1994,
respectively................................................................... 1,071,618 1,343,475
------------- -------------
Total assets..................................................................... $ 2,333,224 $ 2,412,692
------------- -------------
------------- -------------
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders............................................. $ 83,674 $ 261,543
Reserve for future Trust expenses................................................ 1,177,932 807,674
Commitments and contingencies (Note 7)
Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding
at December 31, 1995 and 1994)................................................. 1,071,618 1,343,475
------------- -------------
Total liabilities and trust corpus............................................... $ 2,333,224 $ 2,412,692
------------- -------------
------------- -------------
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1995 1994 1993
-------------- -------------- --------------
<S> <C> <C> <C>
Trust corpus, beginning of year........................... $ 1,343,475 $ 2,036,295 $ 2,555,031
Distributable income...................................... 614,836 2,650,823 1,668,678
Distributions to Unit holders............................. (614,836) (2,650,823) (1,668,678)
Amortization of overriding royalty interest............... (271,857) (692,820) (518,736)
-------------- -------------- --------------
Trust corpus, end of year................................. $ 1,071,618 $ 1,343,475 $ 2,036,295
-------------- -------------- --------------
-------------- -------------- --------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
39
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 Unit holders.
On November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired most of the
Gulf of Mexico offshore oil and gas properties of Tenneco, including all the
Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as
the Working Interest Owner and Managing General Partner of the Partnership.
Chevron also assumed Tenneco's obligations under the Conveyance.
On October 30, 1992, Pennzoil Company ("Pennzoil") acquired certain oil and
gas producing properties from Chevron, including four of the Royalty Properties.
The four Royalty Properties acquired by Pennzoil were East Cameron 354, Eugene
Island 348, Eugene Island 367 and Eugene Island 208. As a result of such
acquisition, Pennzoil replaced Chevron as the Working Interest Owner of such
properties on October 30, 1992. Pennzoil also assumed Chevron's obligations
under the Conveyance with respect to such properties.
On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco")
acquired one of the Royalty Properties from Chevron. The Royalty Property
acquired by Texaco was West Cameron 643. As a result of such acquisition, Texaco
replaced Chevron as the Working Interest Owner of such property on December 1,
1994. Texaco also assumed Chevron's obligations under the Conveyance with
respect to such property.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from Pennzoil. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
Pennzoil. As a result of such acquisitions, SONAT and Amoco have replaced
Pennzoil as the Working Interest Owner of the East Cameron 354 and Eugene Island
367 properties, respectively, and also have assumed Pennzoil's obligations under
the Conveyance with respect to such properties.
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 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
40
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(1) TRUST ORGANIZATION AND PROVISIONS -- (CONTINUED) Cameron 643 thereafter;
Pennzoil with respect to East Cameron 354, Eugene Island 348, Eugene Island 367
and Eugene Island 208 for periods from October 30, 1992 until October 1, 1995
and with respect to Eugene Island 348 and Eugene Island 208 thereafter; Texaco
with respect to West Cameron 643 for periods beginning on or after December 1,
1994; SONAT with respect to East Cameron 354 for periods beginning on or after
October 1, 1995; and Amoco with respect to Eugene Island 367 for periods
beginning on or after October 1, 1995).
On January 14, 1983, Tenneco Offshore distributed units of beneficial
interest ("Units") in the Trust to holders of Tenneco Offshore's common stock on
the basis of one Unit for each common share owned on such date.
The terms of the Trust Agreement, dated January 1, 1983, provide, among
other things, that:
(a) the Trust is a passive entity and cannot engage in any business
or investment activity or purchase any assets;
(b) the interest in the Partnership can be sold in part or in total
for cash upon approval of a majority of the Unit holders;
(c) the Trustees 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 administrative expenses was
increased each quarter by an amount equal to the difference between
$150,000 and the amount of the Trust's general and administrative expenses
for such quarter. In March 1994, the Trust determined, in accordance with
the Trust Agreement, to begin further increasing the Trust's cash reserve
each quarter by an amount equal to the difference between $200,000 and the
amount of the Trust's general and administrative expenses for such quarter.
During 1993, 1994 and 1995, the aggregate amount of cash reserved by the
Trust was $151,336, $347,638 and $370,258, respectively, bringing the total
amount of the Trust's cash reserve at December 31, 1995 to $1,177,932.
(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 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 $7.7 million as of October 31, 1995. (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 was administered by Texas Commerce Bank National
Association ("Corporate Trustee") and Horace C. Bailey, George Allman,
Jr. and W. Leslie Duffy ("Individual Trustees"), as trustees
("Trustees"). On March 10, 1995, the Corporate Trustee was advised of the
death of Horace C. Bailey. In accordance with the terms of the TEL
Offshore Trust Agreement (the "Trust Agreement"), Richard L. Melton was
appointed by George Allman, Jr. and W. Leslie Duffy, the remaining
individual trustees, to replace Mr. Bailey effective April 20, 1995. The
term
41
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(1) TRUST ORGANIZATION AND PROVISIONS -- (CONTINUED)
"Individual Trustees" as used herein includes Mr. Allman, Mr. Duffy, and,
with respect to time periods occurring on or after April 20, 1995, Mr.
Melton. The Individual Trustees and the Corporate Trustee may hereinafter
collectively be referred to as Trustees.
(2) OVERRIDING ROYALTY INTEREST
The Royalty entitles the Trust to its share (99.99%) of 25% of the Net
Proceeds attributable to the Royalty Properties. The Conveyance, dated January
1, 1983, provides that the Working Interest Owners will calculate, for each
period of three months commencing the first day of February, May, August and
November, an amount equal to 25% of the net proceeds from its oil and gas
properties for the period. Generally, Net Proceeds are the amounts received by
the Working Interest Owners from the sale of minerals from its oil and gas
properties less operating and capital costs incurred, management fees and
expense reimbursements owing the managing general partner of the Partnership,
applicable taxes other than income taxes, and cash escrows. Cash escrows are for
the future costs to be incurred to plug and abandon wells, dismantle and remove
platforms, pipelines and other production facilities, and for the estimated
amount of future capital expenditures on the Royalty Properties. Net proceeds do
not include amounts received by the Working Interest Owners as advance gas
payments, "take-or-pay" payments or similar payments unless and until such
payments are extinguished or repaid through the future delivery of gas.
Crude oil sales to Chevron accounted for approximately 73%, 71% and 67% of
crude oil revenues from the Royalty Properties during 1995, 1994 and 1993,
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 1995 ranged from $15.33 per bbl to $17.93 per
bbl. The average price of crude oil sold under this arrangement for February
1996 was approximately $17.25 per bbl. Sales to Texaco Inc. accounted for
approximately 24%, 27% and 30% of crude oil revenues from the Royalty Properties
during 1995, 1994 and 1993, respectively. Sales to Tennessee Gas Pipeline
Company accounted for approximately 42%, 71% and 83% of total gas revenues from
the Royalty Properties during 1995, 1994 and 1993, respectively. The majority of
the remaining gas revenues were attributable to gas purchases by Columbia Gas
Transmission Company (31%) and Penn Union (21%).
The Trust's share of Royalty income was reduced by approximately $120,000,
$158,000 and $188,000 in 1995, 1994 and 1993, 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
42
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(3) BASIS OF ACCOUNTING -- (CONTINUED)
basis. In addition, amortization of the overriding royalty interest, calculated
on a unit-of-production basis, is charged directly to Trust corpus since such
amount does not affect distributable income.
Cash and cash equivalents include all highly liquid short term investments
with original maturities of three months or less.
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 is
effective for financial statements for fiscal years beginning after December 15,
1995. SFAS No. 121 is not anticipated to have a material impact on the financial
position or distributable income of the Trust.
(4) DISTRIBUTIONS TO UNIT HOLDERS
In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. The
amounts distributed are determined on a quarterly basis and are payable to Unit
holders of record as of the last business day of each calendar quarter. However,
cash distributions are made in January, April, July and October and include
interest earned from the quarterly record date to the date of distribution.
(5) SPECIAL COST ESCROW ACCOUNT
The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the 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
$101,500, $103,500 and $112,500 for 1993, 1994 and 1995, respectively, serves to
reduce the Trust's share of allocated production costs. As of December 31, 1993,
1994 and 1995, approximately $4,076,000, $2,365,000 and $2,572,000,
respectively, remained in the Special Cost Escrow Account. Special Cost Escrow
funds will generally be utilized to pay Special Costs to the extent there are
not adequate current net proceeds to pay such costs. Special Costs that have
been paid are no longer included in the Special Cost Escrow calculation.
Deposits to the Special Cost Escrow Account will generally be made when the
balance in the Special Cost Escrow Account is less than 125% of future Special
Costs and there is a Net Revenues Shortfall (a calculation of the excess of
estimated future costs over estimated future net revenues pursuant to a formula
contained in the Conveyance). When there is not a Net Revenues Shortfall,
amounts in the Special Cost Escrow Account will generally be released, to the
extent that Special Costs have been incurred. Amounts in the Special Cost Escrow
Account 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 1996, the current escrow balance, current estimates
of aggregate future capital expenditures, aggregate future abandonment costs,
aggregate future production costs, aggregate
43
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(5) SPECIAL COST ESCROW ACCOUNT -- (CONTINUED)
future net revenues and current net proceeds resulted in a deposit of funds into
the Special Cost Escrow Account amounting to $982,600. The deposit was primarily
a result of an increase in the current 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.
In 1995, the Working Interest Owners deposited a net amount of
approximately $207,000 into the Special Cost Escrow Account. The deposit was
primarily a result of an increase in the current estimate of projected capital
expenditures on the Royalty Properties. As of December 31, 1995, approximately
$2,572,000 remained in the Special Cost Escrow Account.
In 1994, the Working Interest Owners released a net amount of approximately
$1,711,000 from the Special Cost Escrow Account due primarily as a result of a
decrease in future estimated Special Costs of the Royalty Properties. This
decrease was due in part to a decrease in estimated abandonment costs as a
result of technological improvements in abandonment procedures utilized by the
Working Interest Owners and fewer capital projects planned in the future. As of
December 31, 1994, approximately $2,365,000 remained in the Special Cost Escrow
Account.
In 1993, the Working Interest Owners deposited a net amount of
approximately $700,000 into the Special Cost Escrow Account due primarily as a
result of an increase in future estimated production costs of the Royalty
Properties due to wells drilled during 1992 and other expenditures projected by
the Working Interest Owners. As of December 31, 1993, there was approximately
$4,076,000 in the Special Cost Escrow Account.
(6) FEDERAL INCOME TAX MATTERS
The Internal Revenue Service ("IRS") has ruled that the Trust is a grantor
trust and therefore the Trust will incur no federal income tax liability.
(7) COMMITMENTS AND CONTINGENCIES
During 1994, Pennzoil, the Working Interest Owner on the Eugene Island 348
property, settled the 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 $5,000 and $150,000 was recovered from the
Trust by the Working Interest Owner during 1994 and 1995, respectively, and the
remainder will be subject to recovery from the Trust in future periods, in
accordance with the Conveyance. The Working Interest Owner has advised the Trust
that future Royalty income attributable to all of the Royalty Properties owned
by Pennzoil will be used to offset the Trust's share of such settlement amounts.
Based on current production, prices and expenses for the Royalty Properties
owned by Pennzoil, it is estimated that Royalty income attributable to such
properties will be retained by Pennzoil for the remaining life of the Trust. The
Trust does not anticipate that retention of such Royalty income by Pennzoil will
have a material effect on the Trust's Royalty income as a whole.
The Working Interest Owners have advised the Trust that, although they
believe that they are in general compliance with applicable health, safety and
environmental laws and regulations that have taken effect at the federal, state
and local levels, costs may be incurred to comply with current and proposed
environmental legislation which could result in increased operating expenses on
the Royalty Properties.
44
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(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
October 31, 1995, 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 approximately 265,300
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 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 $306,800 in 1995 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,
1995, 1994 and 1993 included net proceeds relating to production of reserves
from the Royalty Properties for the twelve months ended October 31, 1995, 1994
and 1993, respectively. Accordingly, all reserve information included in the
tables below is as of October 31, 1995, 1994 and 1993.
45
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(8) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) -- (CONTINUED)
Estimated net proved reserves attributable to the Partnership's royalty
interest for the periods indicated, are as follows:
<TABLE>
<CAPTION>
PARTNERSHIP
------------------------
OIL AND NATURAL
CONDENSATE GAS
(BBLS) (MCF)
---------- ---------
Proved Developed and Undeveloped Reserves:
<S> <C> <C>
October 31, 1992.................................................................. 426,773 2,351,568
Revisions of previous estimates(a)................................................ 26,335 134,630
Extensions, discoveries and other additions....................................... 291 7,013
Royalty production................................................................ (75,211) (443,186)
---------- ---------
October 31, 1993.................................................................. 378,188 2,050,025
---------- ---------
---------- ---------
October 31, 1993.................................................................. 378,188 2,050,025
Revisions of previous estimates(a)................................................ (16,127) 569,369
Royalty production................................................................ (138,994) (728,905)
---------- ---------
October 31, 1994.................................................................. 223,067 1,890,489
Additional disclosures:
Reserves related to Pennzoil(d)................................................... (3,536) (269,976)
---------- ---------
October 31, 1994, net of reserves related to Pennzoil............................. 219,531 1,620,513
---------- ---------
---------- ---------
October 31, 1994.................................................................. 223,067 1,890,489
Revisions of previous estimates(a)................................................ 185,986 (216,130)
Royalty production................................................................ (73,078) (235,036)
---------- ---------
October 31, 1995.................................................................. 335,975 1,439,323
Additional disclosures:
Reserves related to Pennzoil(d).................................................. (457) (110,567)
---------- ---------
October 31, 1995, net of reserves related to Pennzoil............................ 335,518 1,328,756
---------- ---------
---------- ---------
Proved Developed Reserves:
October 31, 1992.................................................................. 426,636 2,343,234
---------- ---------
---------- ---------
October 31, 1993.................................................................. 378,051 2,041,683
---------- ---------
---------- ---------
October 31, 1994.................................................................. 222,930 1,882,153
Additional disclosures:
Reserves related to Pennzoil(d).................................................. (3,536) (269,976)
---------- ---------
October 31, 1994, net of reserves related to Pennzoil............................ 219,394 1,612,177
---------- ---------
---------- ---------
October 31, 1995.................................................................. 201,110 922,502
Additional disclosures:
Reserves related to Pennzoil(d).................................................. (457) (110,567)
---------- ---------
October 31, 1995, net of reserves related to Pennzoil............................ 200,653 811,935
---------- ---------
---------- ---------
</TABLE>
(SEE NOTES ON FOLLOWING PAGE)
46
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, 1995, 1994 and 1993:
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
(THOUSANDS)
<S> <C> <C> <C>
Future royalty income............................................ $ 7,693 $ 6,480 $ 10,486
Discount at 10% per annum........................................ (2,168) (1,335) (1,974)
--------- --------- ---------
Standardized measure of discounted future royalty income from
proved oil and gas reserves, discounted at 10% per annum(c).... 5,525 5,145 8,512
Additional disclosures:
Amounts attributable to Pennzoil(d)............................ (140) (401) --
--------- --------- ---------
Standardized measure of discounted future royalty income from proved oil and
gas reserves, discounted at 10% per annum,
net of amounts attributable to Pennzoil(c).................. $ 5,385 $ 4,744 $ 8,512
--------- --------- ---------
--------- --------- ---------
</TABLE>
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, 1995, 1994 and 1993:
1995 1994 1993
--------- --------- ---------
(THOUSANDS)
Beginning balance(c)................. $ 5,145 $ 8,512 $ 11,676
Revisions of previous
estimates(a)................. 1,997 (2,328) (1,776)
Royalty income..................... (1,383) (3,435) (2,261)
Accretion of discount.............. 515 851 1,168
Other(b)........................... (749) 1,545 (295)
--------- --------- ---------
Net changes in standardized
measure................. 380 (3,367) (3,164)
--------- --------- ---------
Ending balance(c).................... 5,525 5,145 8,512
Additional disclosures:
Amounts attributable to
Pennzoil(d).................. (140) (401) --
--------- --------- ---------
Ending balance, net of amounts
attributable to
Pennzoil(c).................. $ 5,385 $ 4,744 $ 8,512
--------- --------- ---------
--------- --------- ---------
- ------------
NOTES:
(a) Primarily represents net effect of changes in prices, cost estimates and
reserve quantity revisions attributable to the Royalty Properties on the
royalty computation.
(b) Primarily represents changes in estimated timing of production and changes
in the Special Cost Escrow Account.
(c) Future income taxes are not applicable for purposes of these estimates since
the Partnership is a nontaxable entity.
(d) As a result of the imbalance settlement by Pennzoil, discussed in Note 7,
the associated volumes and future royalty income related to the Pennzoil
owned properties have been excluded from the Trust's Supplemental Reserve
Information, beginning in 1994.
47
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(9) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
SUMMARIZED QUARTERLY RESULTS
THREE MONTHS ENDED*
----------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
------------- ------------- ------------- -------------
Year Ended December 31, 1995:
<S> <C> <C> <C> <C>
Royalty income......................... $ 262,469 $ 377,894 $ 468,689 $ 274,406
Distributable income................... $ 68,619 $ 185,448 $ 277,095 $ 83,674
Distributions per Unit................. $ .014441 $ .039029 $ .058317 $ .017609
Year Ended December 31, 1994:
Royalty income......................... $ 1,605,518 $ 677,359 $ 696,241 $ 456,194
Distributable income................... $ 1,408,156 $ 480,730 $ 500,394 $ 261,543
Distributions per Unit................. $ .296359 $ .101174 $ .105312 $ .055044
</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
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant. The
Trustees consist of a Corporate Trustee and three Individual Trustees. Any
Trustee may be removed by the affirmative vote of two Individual Trustees or by
the affirmative vote of a majority of the Units at a meeting of Unit holders of
beneficial interest in the Trust at which a quorum is present.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS.
As of April 3, 1996, no person was known to be the beneficial owner of more
than five percent of the Units of beneficial interest in the Trust.
(B) SECURITY OWNERSHIP OF MANAGEMENT.
Not applicable.
(C) CHANGES IN CONTROL.
Registrant knows of no arrangements, including the pledge of securities of
the Registrant, the operation of which may at a subsequent date result in a
change in control of the Registrant.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Each of the Working Interest Owners owns interests, for its own account, in
leases which are in the same area as leases in which the Partnership has
acquired or may acquire an interest. Such relationships may give rise to
potential conflicts of interests in, among other things, the operation of such
leases and in the acquisition and operation of any drainage leases acquired by a
Working Interest Owner for its own account. Additionally, the Working Interest
Owners and their affiliates are not prohibited from purchasing oil and gas
produced from or attributable to any leases in which the Partnership has an
interest. Prior to the sale to Chevron, Tenneco also owned interests, for its
own account, in leases in the same area as leases in which the Partnership has
an interest.
Crude oil sales to the Supply and Distribution Department of Chevron and
Texaco accounted for approximately 73% and 24%, respectively, of total crude oil
revenues from the Royalty Properties during 1995.
The Trust's share of Royalty income was reduced by approximately $120,000
in 1995 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 1995.
49
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) (1) FINANCIAL STATEMENTS
The following financial statements are set forth under Part II, Item 8 of
this Annual Report on Form 10-K on the pages as indicated:
PAGE IN THIS
FORM 10-K
Report of Independent Public Accountants....................... 38
Statements of Distributable Income............................. 39
Statements of Assets, Liabilities and Trust Corpus............. 39
Statements of Changes in Trust Corpus.......................... 39
Notes to Financial Statements.................................. 40
(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>
4(a)* Trust Agreement dated as of January 1, 1983, among Tenneco Offshore
Company, Inc., Texas Commerce Bank National Association, as corporate
trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as
individual trustees (Exhibit 4(a) to Form 10-K for year ended December
31, 1992 of TEL Offshore Trust).......................................... 0-6910 4(a)
4(b)* Agreement of General Partnership of TEL Offshore Trust Partnership
between Tenneco Oil Company and the TEL Offshore Trust, dated
January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended
December 31, 1992 of TEL
Offshore Trust).......................................................... 0-6910 4(b)
4(c)* Conveyance of Overriding Royalty Interests from Exploration I to the
Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992
of TEL Offshore Trust)................................................... 0-6910 4(c)
4(d)* Amendments to TEL Offshore Trust Trust Agreement, dated December 7, 1984
(Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL
Offshore Trust).......................................................... 0-6910 4(d)
4(e)* Amendment to the Agreement of General Partnership of TEL Offshore Trust
Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K
for year ended December 31, 1992 of TEL Offshore Trust).................. 0-6910 4(e)
10(a)* Purchase Agreement, dated as of December 7, 1984 by and between Tenneco
Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K
for year ended December 31, 1992 of TEL Offshore Trust).................. 0-6910 10(a)
10(b)* Consent Agreement, dated November 16, 1988, between TEL Offshore
Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for
year ended
December 31, 1988 of TEL Offshore Trust)................................. 0-6910 10(b)
10(c)* Assignment and Assumption Agreement, dated November 17, 1988, between
Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form
10-K for year ended December 31, 1988 of TEL Offshore Trust)............. 0-6910 10(c)
10(d)* Gas Purchase and Sales Agreement Effective September 1, 1993 between
Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company
(Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of TEL
Offshore Trust).......................................................... 0-6910 10(d)
27(a) Financial Data Schedule
</TABLE>
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange
Commission during the fourth quarter of 1995. During the first quarter of 1996,
the Trust filed a current report on Form 8-K, dated January 22, 1996, in
connection with Chevron's drilling of the F-2 delineation gas well on the Ship
Shoal 182/183 property. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for further information regarding such
drilling.
50
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 12TH DAY OF
APRIL, 1996.
TEL OFFSHORE TRUST
By TEXAS COMMERCE BANK NATIONAL
ASSOCIATION, CORPORATE TRUSTEE
By ___/s/__MICHAEL J. ULRICH_______
MICHAEL J. ULRICH
SENIOR VICE PRESIDENT
& TRUST OFFICER
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE DATE
TEXAS COMMERCE BANK NATIONAL
ASSOCIATION, Corporate Trustee
ByMICHAEL J. ULRICH April 12, 1996
MICHAEL J. ULRICH
SENIOR VICE PRESIDENT
& TRUST OFFICER
INDIVIDUAL TRUSTEES
/s/GEORGE ALLMAN, JR. April 12, 1996
GEORGE ALLMAN, JR., TRUSTEE
/s/W. LESLIE DUFFY April 12, 1996
W. LESLIE DUFFY, TRUSTEE
/s/RICHARD L. MELTON April 12, 1996
RICHARD L. MELTON, TRUSTEE
51
THIS ANNUAL REPORT ON FORM 10-K WAS DISTRIBUTED TO UNIT HOLDERS AS AN
ANNUAL REPORT. ADDITIONAL COPIES OF THIS ANNUAL REPORT WILL BE PROVIDED, WITHOUT
CHARGE, AND COPIES OF EXHIBITS HERETO WILL BE PROVIDED, UPON PAYMENT OF A
REASONABLE FEE, UPON WRITTEN REQUEST FROM ANY HOLDER OF UNITS TO:
TEL Offshore Trust
Texas Commerce Bank National Association, Trustee
Attention: Debbie Miller, Corporate Trust Department
P.O. Box 4717
Houston, Texas 77210-4717
AUDITORS COUNSEL TRANSFER AGENT AND REGISTRAR
Arthur Andersen LLP Andrews & Kurth L.L.P. American Stock Transfer
Houston, Texas Houston, Texas & Trust Co. as agent for
Texas Commerce Bank, N.A.
Houston, Texas
TEL OFFSHORE TRUST
P.O. Box 4717
Houston, Texas 77210-4717
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS AS OF DEC-31-1995 AND
THE STATEMENT OF DISTRIBUTABLE INCOME FOR THE YEAR ENDED DEC-31-1995 AND
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 1,261,606
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,261,606
<PP&E> 28,267,655
<DEPRECIATION> 27,196,037
<TOTAL-ASSETS> 2,333,224
<CURRENT-LIABILITIES> 83,674
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 1,071,618
<TOTAL-LIABILITY-AND-EQUITY> 2,333,224
<SALES> 0
<TOTAL-REVENUES> 1,414,836
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 800,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 614,836
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 614,836
<EPS-PRIMARY> .129
<EPS-DILUTED> .129
</TABLE>
