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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-Q

|ý |  | Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended September 30, 2002
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------

or

|o |  | 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

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TEL OFFSHORE TRUST(Exact Name of Registrant as Specified in its Charter)

Texas(State of Incorporation,
or Organization)

76-6004064I.R.S. Employer
Identification No.)JPMorgan Chase Bank, Trustee
Institutional Trust Services
700 Lavaca Street
Austin, Texas(Address of Principal
Executive Offices)

78701(Zip Code)


Registrant's
Telephone Number, Including Area Code:(512) 479-2562

Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past
90 days.    Yes X    No

Indicate
the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

As
of November 13, 20024,751,510 Units of Beneficial Interest in TEL Offshore Trust.

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Note Regarding Forward-Looking Statements

This
Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-Q are forward-looking statements. Although the Working
Interest Owners (as defined herein) have advised the Trust that they believe that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be
given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this
Form 10-Q, including without limitation in conjunction with the forward-looking statements included in this Form 10-Q. A summary of certain principal risks and
Cautionary Statements is also included in the Trust's Form 10-K under "BusinessPrincipal Trust Risk Factors." 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.

i

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PART IFINANCIAL INFORMATION

Item 1. Financial Statements.

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

|                                                                                                                                        |  | September 30,
2002 |           | December 31,
2001
|--------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------ | --------- | -----------------
|
|Assets                                                                                                                                  |  |                    |           |                  
|Cash and cash equivalents                                                                                                               |  | $                  | 1,614,095 |                  
|Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,069,089 and $28,047,080, respectively |  |                    | 198,566   |                  
|                                                                                                                                        |  |                    |           |                  
|Total assets                                                                                                                            |  | $                  | 1,812,661 |                  
|                                                                                                                                        |  |                    |           |                  
|Liabilities and Trust Corpus                                                                                                            |  |                    |           |                  
|Distribution payable to Unit holders                                                                                                    |  | $                  | 617,102   |                  
|Reserve for future Trust expenses                                                                                                       |  |                    | 996,993   |                  
|Commitments and contingencies (Note 7)                                                                                                  |  |                    |           |                  
|Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)                                                        |  |                    | 198,566   |                  
|                                                                                                                                        |  |                    |           |                  
|Total liabilities and Trust corpus                                                                                                      |  | $                  | 1,812,661 |                  
|                                                                                                                                        |  |                    |           |                  

STATEMENTS OF DISTRIBUTABLE INCOME  (Unaudited)

|                                                         |  | Three Months Ended
September 30, |         | Nine Months Ended
September 30, |  
|-------------------------------------------------------- |  | -------------------------------- | ------- | ------------------------------- | -
|
|Royalty income                                           |  | $                                | 694,442 |                                 | $
|Interest income                                          |  |                                  | 3,734   |                                 |  
|                                                         |  |                                  |         |                                 |  
|                                                         |  |                                  | 698,176 |                                 |  
|(Increase)/Decrease in reserve for future Trust expenses |  |                                  | 0       |                                 |  
|General and administrative expenses                      |  |                                  | (81,074 | )                               |  
|Other                                                    |  |                                  | 0       |                                 |  
|                                                         |  |                                  |         |                                 |  
|Distributable income                                     |  | $                                | 617,102 |                                 | $
|                                                         |  |                                  |         |                                 |  
|Distributions per Unit (4,751,510 Units)                 |  | $                                | .129875 |                                 | $
|                                                         |  |                                  |         |                                 |  

The
accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CHANGES IN TRUST CORPUS  (Unaudited)

|                                                |  | Three Months Ended
September 30, |          | Nine Months Ended
September 30, |  
|----------------------------------------------- |  | -------------------------------- | -------- | ------------------------------- | -
|
|Trust corpus, beginning of period               |  | $                                | 207,120  |                                 | $
|Distributable income                            |  |                                  | 617,102  |                                 |  
|Distribution payable to Unit holders            |  |                                  | (617,102 | )                               |  
|Amortization of net overriding royalty interest |  |                                  | (8,554   | )                               |  
|                                                |  |                                  |          |                                 |  
|Trust corpus, end of period                     |  | $                                | 198,566  |                                 | $
|                                                |  |                                  |          |                                 |  

The
accompanying notes are an integral part of these financial statements.

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1Trust Organization

Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of
Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was formed in which the
Trust owns a 99.99% interest and Tenneco Oil Company ("Tenneco") initially owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest ("Royalty")
equivalent to a 25% net profits interest in the oil and gas properties (the "Royalty Properties") of Tenneco Exploration, Ltd. ("Exploration I") located offshore Louisiana to the Partnership
and issuing certificates evidencing units of beneficial interest in the Trust ("Units") in liquidation and cancellation of Tenneco Offshore's common stock.

On
October 31, 1986, Exploration I was dissolved and the oil and gas properties of Exploration I were distributed to Tenneco subject to the Royalty. Tenneco, who was then serving
as the Managing General Partner of the Partnership, assumed the obligations of Exploration I, including its obligations under the instrument conveying the Royalty to the Partnership (the
"Conveyance"). The dissolution of Exploration I had no impact on future cash distributions to holders of units of beneficial interest.

On
November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco, including all the Royalty Properties.
As a result of the acquisition, Chevron replaced Tenneco as the Working Interest Owner and Managing General Partner of the Partnership. Chevron also assumed Tenneco's obligations under the Conveyance.

On
October 30, 1992, PennzEnergy Company ("PennzEnergy") (which merged with and into Devon Energy Production Company L.P. effective January 1, 2000) acquired certain oil
and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by PennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 and
Eugene Island 208. As a result of such acquisition, PennzEnergy replaced Chevron as the Working Interest Owner of such properties on October 30, 1992. PennzEnergy also assumed Chevron's
obligations under the Conveyance with respect to such properties.

On
December 1, 1994, Texaco Exploration and Production Inc. ("TEPI") acquired two of the Royalty Properties from Chevron. The Royalty Properties acquired by Texaco were
West Cameron 643 and East Cameron 371/381. As a result of such acquisitions, TEPI replaced Chevron as the Working Interest Owner of such properties on December 1, 1994. TEPI also assumed
Chevron's obligations under the Conveyance with respect to such properties.

On
October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco Production Company
("Amoco") acquired the Eugene Island 367 property from PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced PennzEnergy as the Working Interest Owners of the East Cameron 354 and
Eugene Island 367 properties, respectively, on October 1, 1995 and also assumed PennzEnergy's obligations under the Conveyance with respect to such properties.

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Effective
January 1, 1998, Energy Resource Technology, Inc. ("ERT") acquired the East Cameron 354 property from SONAT. As a result of such acquisition, ERT replaced SONAT
as the Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed SONAT's obligations under the Conveyance with respect to such property. In
October 1998, Amerada Hess Corporation ("Amerada") acquired the East Cameron 354 property from ERT effective January 1, 1998. As a result of such acquisition, Amerada replaced ERT as the
Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed ERT's obligations under the Conveyance with respect to such property.

Effective
January 1, 2000 PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon Energy Production Company L.P ("Devon"). As a result of this merger, Devon replaced
PennzEnergy as the Working Interest Owner of Eugene Island 348 and Eugene Island 208 properties effective
January 1, 2000, and also assumed PennzEnergy's obligations under the Conveyance with respect to such properties.

On
October 9, 2001, a wholly owned subsidiary of Chevron Corporation, a Delaware corporation, merged with and into Texaco Inc., a Delaware corporation ("Texaco"), pursuant
to an Agreement and Plan of Merger, dated as of October 15, 2000 (the "Merger"). As a result of the Merger, Texaco Inc. became a wholly owned subsidiary of Chevron Corporation, and
Chevron Corporation changed its name to "ChevronTexaco Corporation" (ChevronTexaco Corporation is referred to herein as "ChevronTexaco"). Accordingly, the properties referred to herein as being owned
by Chevron, are each now controlled by a subsidiary of ChevronTexaco.

On
May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371/381 to Chevron. Accordingly, pursuant to the Conveyance of the Royalty Properties, Net
Proceeds will be calculated for the collective Royalty Properties owned by Chevron after this date.

All
of the Royalty Properties continue to be subject to the Royalty, and it is anticipated that the Trust and the Partnership, in general, will continue to operate as if the
above-described sales of the Royalty Properties had not occurred.

Unless
the context in which such terms are used indicates otherwise, in these Notes to Financial Statements the terms "Working Interest Owner" and "Working Interest Owners" generally
refer to the owner or owners of the Royalty Properties (Exploration I through October 31, 1986; Tenneco for periods from October 31, 1986 until November 18, 1988; Chevron with
respect to all Royalty Properties for periods from November 18, 1988 until October 30, 1992, and with respect to all Royalty Properties except East Cameron 354, Eugene Island 348, Eugene
Island 367 and Eugene Island 208 for periods from October 30, 1992 until December 1, 1994, and with respect to the same properties except West Cameron 643 and East Cameron 371/381 from
December 1, 1994 until May 1, 2002, and with respect to the same properties including West Cameron 643 and East Cameron 371/381 thereafter; PennzEnergy with respect to East Cameron 354,
Eugene Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until October 1, 1995, and with respect to Eugene Island 348 and Eugene Island 208 until
January 1,

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2000; TEPI with respect to West Cameron 643 and East Cameron 371/381 for periods beginning on December 1, 1994 until May 1, 2002; SONAT with respect to East Cameron 354 for periods
beginning on or after October 1, 1995; and Amoco with respect to Eugene Island 367 for periods beginning on or after October 1, 1995; and Amerada with respect to East Cameron 354 for
periods beginning on or after January 1, 1998; and Devon with respect to Eugene Island 348 and Eugene Island 208 for periods beginning on or after January 1, 2000).

Note 2Basis of Accounting

The accompanying unaudited financial information has been prepared by JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank and the successor by mergers
to the original name of the Corporate Trustee, Texas Commerce Bank, National Association) ("Corporate Trustee") in accordance with the instructions to Form 10-Q and does not include
all of the information required by accounting principles generally accepted in the United States of America for complete financial statements, although the Corporate Trustee and the individual
trustees (collectively, the "Trustees") believe that the disclosures are adequate to make the information presented not misleading. The information furnished reflects all adjustments, which are, in
the opinion of the Trustees, necessary for a fair presentation of the results for the interim periods presented. The financial information should be read in conjunction with the financial statements
and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2001.

The
financial statements of the Trust are prepared on the following basis:



This
manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the
Working Interest Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the overriding royalty interest, which is calculated on
a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.

Cash
and cash equivalents include all highly liquid, short-term investments with original maturities of three months or less.

The
Trust reviews net overriding royalty interest in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not be
recoverable. If

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there
is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset and its eventual
disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss is recognized to write down the asset to its estimated fair value. Preparation of estimated expected
future cash flows is inherently subjective and is based on management's best estimate of assumptions concerning expected future conditions. There were no write-downs taken in the periods presented.

The
preparation of financial statements requires the Trustees to make use of estimates and assumptions that affect amounts reported in the financial statements as well as certain
discounts. Actual results could differ from those estimates.

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. 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. The
Trust does not enter into any hedging transactions on future production. Accordingly, the Statement of Financial Accounting Standards No. 133, "Accounting of Derivative Instruments and Hedging
Activities," as amended, that was effective January 1, 2001 has not had an impact on the financial statements.

Note 3Net Overriding Royalty Interest

The Royalty entitles the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance, dated January 1,
1983, provides that the Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the Net
Proceeds from their oil and gas properties for the period. Generally, Net Proceeds are the amounts received by the Working Interest Owners from the sale of minerals from the Royalty Properties less
operating and capital costs incurred, management fees and
expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and a special cost reserve. The Special Cost Reserve Account is established
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.

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Note 4Distributions to Unit Holders

In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and
any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. The amounts distributed are determined on a quarterly
basis and are payable to Unit holders of record as of the last business day of each calendar quarter. However, cash distributions are made in January, April, July and October and include interest
earned from the quarterly record date to the date of distribution.

Note 5Special Cost Escrow Account

The Conveyance provides for the reserve of funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of
abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royal Properties. As provided in the Conveyance, the amount of
funds to be reserved is determined based on certain 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 serves to reduce the Trust's share of allocated production costs. Special
Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been paid are no longer included
in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow Account will generally be made when the balance in the Special Cost Escrow Account is less than 125% of future Special Costs
and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a
Net Revenues Shortfall, amounts in the Special Cost Escrow
Account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow Account generally will also be released when the balance in such account
exceeds 125% of future Special Costs. In the first nine months of 2001, there was a net deposit of funds into the Special Escrow Account. The Trust's share of the funds deposited was $315,509. This
deposit was also primarily a result of an increase in the Working Interest Owner's current estimate of projected capital expenditures of the Royalty Properties. In the first nine months of 2002, there
was a net release of funds from the Special Cost Escrow Account. The Trust's share of the funds released was $411,575. The release was made primarily due to a decrease in the estimate of projected
capital expenditures, production costs and abandonment costs of the Royalty Properties. As of September 30, 2002, $5,041,112 remained in the Special Cost Escrow Account.

Chevron,
in its capacity as Managing General Partner, has advised the Trust that 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

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which such deposits are made, including the possibility that no Royalty income would be received in such periods.

Note 6Expense Reserve

The Trustees made a determination in 1998 to maintain a cash reserve equal to three times the average expenses of the Trust during each of the past three years to
provide for future administrative expenses in connection with the winding up of the Trust. The reserve amount for 2001 was $978,971. The excess amount in the reserve at January 1, 2001, of
$138,513 was distributed to Unit holders in the first quarter of 2001. The reserve amount at September 30, 2002 was calculated to be $996,993. The amount of $18,022 was withheld from Unit
holders in the second quarter of 2002 to maintain the cash reserve. No additional cash reserves were required during the third quarter of 2002. The next expense reserve determination will occur in the
first quarter of 2003.

Note 7Commitments and Contingencies

During 1994, the Working Interest Owner on the Eugene Island 348 property settled a gas imbalance on that property for approximately $2,696,000. The Trust's share
of this settlement amount was approximately $674,000, of which approximately $642,022 has been recovered from the Trust by the Working Interest Owner through the third quarter of 2002. The remainder
will be subject to recovery
from the Trust during future periods in accordance with the Conveyance. Devon has advised the Trust that future Royalty income attributable to all of the Royalty Properties owned by Devon will be used
to offset the Trust's share of such settlement amounts. Based on current production, prices, operational expenses, capital expenditure plans and future abandonment for the Royalty Properties owned by
Devon, it is estimated that while the gas imbalance will end in 2003, Royalty income attributable to such properties will be retained by Devon for the remaining life of the Trust due to Devon's
unfunded special cost escrow account. The Trust does not anticipate that retention of such Royalty income by Devon 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.

On
September 21, 2001, the Trust gave written demand to, and on October 11, 2001, the Trust filed suit against TEPI as the then-current Working Interest Owner of the East
Cameron 371 lease to account for its payment of the Trust's overriding royalty interest in this lease. The case is currently pending in the United States District Court of the Southern District of
Texas, Houston Division, and discovery is ongoing. The Trust believes that TEPI improperly reduced the percentage of Net Proceeds payable to the Trust and improperly deducted from Gross Proceeds
certain costs that the Trust believes are attributable to TEPI's

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separate operations on an offsetting lease. The Trust cannot predict the amount, if any, or the timing if ever, for any recovery relating to these claims. However, such claims may be significant if
recovered and would be payable only to holders of the Trust's Units at the time of distribution.

In
connection with the foregoing litigation, TEPI has also asserted a counterclaim for overpayment of $880,632 prior to and during the third quarter of 1999. TEPI has claimed that these
costs should have been allocated to the Trust. This counterclaim has been asserted notwithstanding Texaco's own internal audit and revisions relating to the same periods in 1998 and described in the
Trust's Form 10-K for the year ended December 31, 1999 and 1998. The Trustees are currently reveiwing the facts relating to this alleged overpayment due to Texaco accounting
errors but have not been provided with sufficient information to understand fully the basis of the claim. Chevron has notified the Corporate Trustee that it currently does not intend to withhold
revenues from production of East Cameron 371/381 in connection with this counterclaim. The Corporate Trustee cannot predict the liklihood that this claim will actually succeed or the actual extent of
this purported accounting error by Texaco.

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

Critical Accounting Policies

The financial statements of the Trust are prepared on the following basis:



This
manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the
Working Interest Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a
units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.

Net Overriding Royalty Interest and Distributions

As discussed in Note 3 of the financial statements, the Royalty created by the Conveyance entitles the Trust to its share (99.99%) of 25% of the Net
Proceeds attributable to the Royalty Properties. The Working Interest Owners are required to calculate, for each period of three months commencing the first day of February, May, August and November,
an amount equal to 25% of the Net Proceeds from
their Royalty Properties for the period. Generally, Net Proceeds are the amounts received by the Working Interest Owner from the sale of minerals from the Royalty Properties less:



Net
Proceeds do not include amounts received by the Working Interest Owners as advance gas payments, "take-or-pay" payment or similar payments unless and until such payments are
extinguished or repaid through the future delivery of gas. The Trustees rely on the Working Interest Owners to make calculations accurately and in good faith during each period.

In
connection with the merger of Chevron and TEPI effective May 1, 2002, calculations of Net Proceeds for the former TEPI-owned Royalty Properties (West Cameron 643 and East
Cameron 371/381) will be combined with the other Royalty Properties owned by Chevron. Based on a pro forma analysis prepared for the Trust by ChevronTexaco, the Corporate Trustee believes that
distributions to the Trust during the first two quarters of 2002 would have been approximately $220,000 less than the $922,000 actually distributed by Chevron and Texaco. This pro forma difference
would have resulted from a payment of Texaco's $179,000 net loss carryforward plus a $58,000 lower distribution from a combined ChevronTexaco Special Cost Escrow Account, offset by $17,000 of interest
earned and distributed by Chevron and TEPI. Accordingly, while the Corporate Trustee cannot predict future effects of this merger,

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the merger may reduce certain future distributions as items reducing Net Proceeds are combined across all of these Royalty Properties.

As
part of the overpayment counterclaim in connection with pending litigation originally instituted by the Trust against TEPI, Chevron has also notified the Corporate Trustee that it
believes TEPI overpaid $880,632 prior to and during the third quarter of 1999. TEPI asserted this as part of an overpayment
counterclaim in connection with the pending litigation originally instituted by the Trust against TEPI. This counterclaim has been asserted notwithstanding Texaco's own national audit and revisions to
the same periods on 1998 and 1999 and described in the Trust's Form 10-K for the year ended December 31, 1999. The Trustees are currently reviewing the facts relating to this alleged accounting
error but have not been provided with sufficient information to understand fully the basis of the claim. Chevron has notified the Corporate Trustee that it currently does not intend to withhold
revenues from production on East Cameron 371/381 in connection with this counterclaim. The Corporate Trustee cannot predict the likelihood that this claim will actually succeed or the actual extent of
this purported accounting error by Texaco.

Financial Review

Three Months Ended September 30, 2002 and 2001

Distributions to the Unit holders for the three months ended September 30, 2002 amounted to $617,102 or $.129875 per Unit as compared to $1,133,580 or
$.238573 per Unit for the same period in 2001. The decrease in distribution income for the third quarter of 2002 was primarily due to decreased oil and gas prices, offset by production volume
declines, as described below.

Gas
revenues decreased 56% to $677,847 in the third quarter of 2002 from $1,521,066 in the third quarter of 2001, primarily due to a 49% decrease in gas volumes to 214,123 Mcf in the
third quarter of 2002 from 378,833 Mcf in the third quarter of 2001. Additionally, the average price received for natural gas decreased 9% to $3.36 per Mcf in the third quarter of 2002 from $3.71 per
Mcf on the third quarter of 2001. The lower gas volumes were primarily due to natural production declines in wells on East Cameron 353, East Cameron 371/381 and Ship Shoal 182/183.

Crude
oil and condensate revenues increased 22% to $5,302,123 in the third quarter of 2002 from $4,345,468 in the third quarter of 2001. Oil volumes during the third quarter of 2002
totaled 217,656 barrels, compared to 164,624 barrels of oil produced in the third quarter of 2001. The higher oil volumes primarily attributable to an increase in Eugene Island 339 offset by a natural
decline on Ship Shoal 182/183.

The
Trust's share of capital expenditures decreased in the third quarter of 2002, to $667,116 as compared to $858,609 in the third quarter of 2001. The lower capital expenditures in the
third quarter of 2002 were due primarily to normalization after the second quarter 2002 C-4 and C-12 major rig workovers on Ship Shoal 182/183, offset by control panel upgrades
on Eugene Island 339 and West Cameron 643B mobilization/demobilization.

For
the third quarter of 2002, the Trust had undistributed net income of $717,088. Undistributed net income represents positive Net Proceeds, generated during the respective period, that
were applied to an existing loss carryforward. Undistributed net loss represents negative Net Proceeds generated during the

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respective period. An undistributed net loss is carried forward and offset, in future periods, by positive Net Proceeds earned by the related Working Interest Owner(s).

In
the third quarter of 2002, there was a net deposit of funds into the Special Cost Escrow Account. The Trust's share of the funds deposited was approximately $171,565 for the third
quarter of 2002, compared to a net release of funds from the Special Cost Escrow Account of $83,867 to the Trust in the third quarter of 2001. The Special Cost Escrow is set aside for estimated
abandonment costs and future capital expenditures as provided for in the Conveyance. For additional information relating to the Special Cost Escrow see "Special Cost Escrow Account" below.

Nine Months Ended September 30, 2002 and 2001

Distributions to Unit holders for the nine months ended September 30, 2002 amounted to $982,043 or $.206680 per Unit, as compared to $4,048,896 or $.85218
per Unit for the same period in 2001. The decrease in distributable income for the first nine months of 2002 was primarily due to decreased oil and gas prices, offset by production volume declines, as
described below.

Gas
revenues decreased to $1,781,947 in the first nine months of 2002 from $8,656,304 in the first nine months of 2001, primarily due to an decrease in the average price received for
natural gas to $2.55 per Mcf in the first nine months of 2002 from $5.74 per Mcf in the first nine months of 2001. The decrease in average price was compounded by a decrease in gas volumes to 700,173
Mcf in the first nine months of 2002 from 1,509,357 Mcf in the first nine months of 2001.

Crude
oil and condensate revenues decreased $2,653,314, or 19%, to $11,465,209 in the first nine months of 2002 as compared to $14,118,523 in the same period in 2001, primarily due to a
decrease in the crude oil and condensate volume from the first nine months of 2002 to the first nine months of 2001. The decrease in crude oil and condensate volumes was compounded by an 25% decrease
in the average price of crude oil and condensate from $29.11 per barrel in the first nine months of 2001 to $21.92 per barrel in the first nine months of 2002.

The
Trust's share of capital expenditures increased to $5,290,009 in the first nine months of 2002 as compared to $1,960,265 for the same period in 2001.

In
the first nine months of 2002, there was a net release of funds into the Special Cost Escrow Account. The Trust's share of the funds deposited was approximately $411,575 compared to a
net deposit of funds into the Special Cost Escrow Account of approximately $315,509 net to the Trust in the first nine months of 2001.

Reserve for Future Trust Expenses

In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and
any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. In 1998, the Trustees determined that cash reserve equal
to three times the average expenses of the Trust during each of the past three years was sufficient at that time to provide for future administrative expenses in connection with the winding up of the
Trust. The reserve amount for 2001 was $978,971. The excess amount in the reserve at January 1, 2001, of $138,513 was distibuted to Unit holders in the first quarter 2002. The reserve amount
for 2002 was calculated to be $996,993. The amount of $18,022 was witheld from

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Unit holders in the second quarter of 2002 to maintain the cash reserve. Although the Trustees have no current plans to change this reserve methodology, the Trustees may in the future review and
modify these reserves as needed.

Other

The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of oil and gas produced from the Royalty
Properties. It should be noted that substantial
uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major petroleum
producing nations, as well as the regional supply and demand for oil and gas, weather, industrial growth, conservation measures, competition and other variables.

Operational Review

Three Months Ended September 30, 2002 and 2001

Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

Ship
Shoal 182/183 crude oil revenues decreased from $2,931,386 in the third quarter of 2001 to $2,172,134 in the third quarter of 2002, primarily due to a decrease in crude oil
production from 110,195 barrels in the third quarter of 2001 to 88,818 barrels in the third quarter of 2002. The decrease in crude oil production was due primarily to continued production decline as
wells continue to produce significant water. The effect of this decrease in crude oil production was compounded by a decrease in the average price of crude oil from $26.60 per barrel in the third
quarter of 2001 to $24.46 per barrel in the third quarter of 2002. Gas revenues decreased from $275,843 in the third quarter of 2001 to $110,969 in the third quarter of 2002, primarily due to a
decrease in gas volumes from 99,770 Mcf in the third quarter of 2001 to 30,264 Mcf in the third quarter of 2002. The decrease in gas revenues was partially offset by an increase in the average natural
gas sales price from $2.76 per Mcf in the third quarter of 2001 to $3.67 per Mcf in the third quarter of 2002. The decrease in gas volumes was primarily due to the C-10 well sanding up and
going off production and the natural production decline of the B-13 well. The gas from Ship Shoal 182/183 is committed to Dynegy Inc. ("Dynegy") at a calculated price based on the monthly
Inside FERC Tennessee-Louisiana Zone 1 Index. In addition, Chevron has advised the Trust that approximately 65,621 Mcf have been overtaken by Chevron from this property as of July 31, 2002. The
Trust's share of this overtake position is approximately 16,405 Mcf. Accordingly, gas revenues from this property may be decreased in future periods while underproduced parties recoup their share of
the gas imbalance. Chevron has advised the Trust that sufficient gas reserves exist on Ship Shoal 182/183 for underproduced parties to recoup their share of the gas imbalance on this property. Capital
expenditures decreased to $242,681 in the third quarter of 2002 from $331,498 in the third quarter of 2001. Operating expenses increased slightly from $422,610 in the third quarter of 2001 to $432,492
for the same period in 2002.

Eugene
Island 339 crude oil revenues increased from $1,197,013 in the third quarter of 2001 to $2,969,849 in the third quarter of 2002, primarily due to a significant increase in crude
oil production from 46,503 barrels in the third quarter of 2001 to 122,576 barrels in the third quarter of 2002. The increase in crude oil production was primarily due to a volume increase resulting
from the B-7 well coming online in June 2002 and the B-9 well coming online in April 2002. The increase in crude oil production was partially

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offset by a decrease in the average price of crude oil from $25.74 per barrel in the third quarter of 2001 to $24.23 per barrel in the third quarter of 2002. Gas revenues increased to $272,483 in the
third quarter of 2002 from $104,531 in the third quarter of 2001, primarily due to revisions made by Chevron in the third quarter of 2001 as well as actual a volume increases as a result of continued
improvement from new flowlines and an upgrade to heater treater and the B-7 and B-9 wells coming online in 2002. Additionally, there was an increase in the average natural gas
sales price from $2.71 per Mcf in the third quarter of 2001 to $2.89 in the third quarter of 2002. Chevron has advised the Trust that there is an undertake imbalance position of approximately 46,915
Mcf on this property as of July 31, 2002. The Trust's share of this undertake position is approximately 11,729 Mcf. Accordingly, gas revenues from this property may be reduced in future periods
while underproduced parties recoup their share of the gas imbalance. Chevron has advised the Trust that sufficient gas reserves exist on the Eugene Island 339 for underproduced parties to recoup their
share of the gas imbalance on this property. The gas from this property is currently committed to Dynegy at a calculated price based on the monthly Inside FERC Tennessee-Louisiana Zone 1 Index.
Capital expenditures for the third quarter of 2002 were $350,456 attributable in past to B-7 and B-9 well expenses, compared to $229,793 in the same period in 2001. Operating expenses were $192,029
for the third quarter of 2002, approximately $90,000 of which relate to second quarter 2002 expenses, compared to $251,846 in the same period in 2001.

West
Cameron 643 gas revenues decreased from $577,825 in the third quarter of 2001 to $63,817 in the third quarter of 2002, primarily due to a decrease in gas volumes from 145,705 in the
third quarter of 2001 to 17,628 in the third quarter of 2002. The decrease in gas volumes was due primarily to the A-14 well being shut in from July 8, 2002 due to a wireline tool
being stuck downhole and the field being down for four days to replace six leaking valves. The decrease in gas volumes was compounded by a decrease in average natural gas sales price from $3.97 per
Mcf in the third quarter of 2001 to $3.62 in the third quarter of 2002. The gas from West Cameron 643 is currently committed to Texaco Natural Gas Inc. ("TNGI"). TNGI is a wholly owned
affiliate of "TEPI". TNGI purchases natural gas from TEPI and resells such gas to a variety of third-party customers at a variety of downstream delivery points. The prices that TNGI pays TEPI for the
gas production is based on the actual sale prices that TNGI receives from its third-party customers less the actual transportation costs, if any, that TNGI pays to a transporting pipeline. TEPI's
proceeds are based on 100% of the actual resale price of the gas, less actual transportation costs. Chevron has advised the Trust that approximately 408 Mcf have been overtaken by the Working Interest
Owner from this property as of April 30, 2002. The Trust's share of this overtake position is approximately 102 Mcf. Accordingly, gas revenues from this property may be reduced in future
periods while underproduced parties recover their share of the gas imbalance. Operating expenses decreased to $217,732 in the third quarter of 2002 from $310,277 in 2001. Operating expenses related to
three tubing workovers on A-10, A-14 and A-17 wells. Capital
expenditures decreased significantly from $269,911 in the third quarter of 2001, when rig mobilization and demobilization expenses were incurred, to $44,699 in the third quarter of 2002.

East
Cameron 371/381 crude oil revenues decreased from $44,130 in the third quarter of 2001 to $25,202 in the third quarter of 2002, primarily due to a decrease in crude oil production
from 1,645 barrels in the third quarter of 2001 to 957 barrels in the third quarter of 2002. Gas revenues decreased from $140,251 in the third quarter of 2001 to $59,427 in the third quarter of 2002,
primarily due to a decrease in gas volumes from 33,656 Mcf in the third quarter of 2001 to 19,944 Mcf in the third quarter of 2002. The average natural gas sales price decreased from $4.17 per Mcf in
the third quarter of 2001 to $2.98 per Mcf in the third quarter of 2002. The gas from East Cameron 371/381 is currently committed to TNGI on terms

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similar to gas committed to West Cameron 643. Operating expenses for the third quarter 2002 were $25,683, an insignificant increase from operating expenses of $21,624 in this same period in 2001. No
capital expenses were recorded in the third quarter of 2002 compared to $7 in the third quarter 2001.

Nine Months Ended September 30, 2002 and 2001

Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

Ship
Shoal 182/183 crude oil revenues decreased from $9,202,980 in the first nine months of 2001 to $6,467,828 in the first nine months of 2002, primarily due to a decrease in the
average price of crude oil from $28.95 per barrel in the first nine months of 2001 to $21.68 per barrel in the first nine months of 2002. Crude oil production decreased slightly from 317,840 barrels
in the nine months of 2001 to 298,282 barrels in the first nine months of 2002. Gas revenues decreased from $1,903,018 in the first nine months of 2001 to $501,269 in the first nine months of 2002,
primarily due to a significant decrease in volumes that was compunded by a decrease in the average natural gas sales price from $5.73 per Mcf in the first nine months of 2001 to $2.58 per Mcf in the
first nine months of 2002. The decrease in gas volumes from 332,049 Mcf in the first nine months of 2001 to 194,275 Mcf in the first nine months of 2002 was primarily a result of the disappointing
results from the I-1 well, the 44% national production decline of the B-13 well, the B15 being taken off production for two weeks in 2002 and the E-10 well sanding up and
remaining off production for the entire third quarter of 2002. Capital expenditures increased from $1,186,642 in the first nine months of 2001 to $3,886,085 in the same period of 2002 primarily due to
development of I-1 wells in the second of 2002. Operating expenses
increased from $1,129,677 for the first nine months of 2001 to $1,193,286 for the first nine months of 2002.

Eugene
Island 339 crude oil revenues increased from $4,153,560 in the first nine months of 2001 to $4,551,470 in the first nine months of 2002, primarily due to an increase in crude oil
production from 142,002 barrels in the first nine months of 2001 to 204,498 barrels in the first nine months of 2002. The substantial increase in crude oil production was due primarily to the B-7 well
coming online in June 2002 and this B-9 well coming online in April 2002. The increase in crude oil production was offset by a signficant decrease in the average price of crude oil from $29.25 per
barrel in the first nine months of 2001 to $22.26 per barrel in the first nine months of 2002. Gas revenues decreased to $360,405 in the first nine months of 2002 from $733,133 in the first nine
months of 2001, primarily due to a significant decrease in the average natural gas sales price from $4.51 per Mcf in the first nine months of 2001 to $2.33 per Mcf in the first nine months of 2002.
Operating expenses decreased from $830,467 for the first nine months of 2001 to $415,593 for the first nine months of 2002. Capital expenditures increased from $312,131 in the first nine months of
2001 to $853,731 in the first nine months of 2002. This increase was due primarily to the B-7 sidetrack workover, B-9 well expenses and inspection program done in 2002.

West
Cameron 643 gas revenues decreased from $3,453,878 in the first nine months of 2001 to $165,474 in the first nine months of 2002, primarily due to a decrease in natural gas volumes
from 596,662 Mcf in the first nine months of 2001 to 59,107 Mcf in the first nine months of 2002. This decrease in production was compounded by a decrease in average natural gas sales price from $5.79
per Mcf in the first nine months of 2001 to $2.80 per Mcf in the first nine months of 2002. The decrease in gas volumes was due to a Columbia Gulf Gas pipeline leak and the B-8 sidetrack
being shut in due to water production. Operating expenses were $628,188 in the first nine months of 2002 as compared to $874,802 in the same

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period in 2001. Capital expenditures increased from $376,838 in the first nine months of 2001 to $474,720 in the first nine months of 2002.

East
Cameron 371/381 crude oil revenues decreased from $148,520 in the first nine months of 2001 to $68,786 in the first nine months of 2002, primarily due to a decrease in crude oil
production from 5,177 barrels in the first nine months of 2001 to 2,968 barrels in the first nine months of 2002. Gas revenues decreased from $807,238 in the first nine months of 2001 to $175,616 in
the first nine months of 2002, primarily due to a decrease in gas volumes from 131,287 Mcf in the first nine months of 2001 to 65,035 Mcf in the first nine months of 2002. The decrease in gas revenues
was compounded by an decrease in the average natural gas sales price from $6.15 per Mcf in the first nine months of 2001 to $2.70 per Mcf in the first nine months of 2002. There were no capital
expenditures for the first nine months of 2002. Operating expenses were $128,090 in the first nine months of 2002 compared to $65,386 in the first nine months of 2001.

Future Net Revenues and Termination of the Trust

Based on a reserve study provided to the Trust by DeGolyer and MacNaughton, independent petroleum engineers, it was estimated that as of October 31, 2001
future net revenues attributable to the Trust's royalty interests approximated $15.2 million. Such reserve study also indicates that approximately 75% of the future net revenues from the
Royalty Properties are expected to be received by the Trust during the next three years. In addition, because the Trust will terminate in the event estimated future net revenues fall below
$2 million, it would be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination of the Trust, the
Trustees will sell for cash all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied. The
estimates of future net revenues discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties present in estimating future
net revenues for the Royalty Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed by
DeGolyer and MacNaughton. In addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth
above is qualified in its entirety by reference to the Trust's 2001 Annual Report on Form 10-K. The Form 10-K is available upon request from the Corporate
Trustee.

Special Cost Escrow Account

The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of
abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount
of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net
proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to
as the "Special Cost Escrow Account." The Trust's share of interest generated from the Special Cost Escrow Account 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

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adequate current net proceeds to pay such costs. Special Costs that have been paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow Account will
generally be made when the balance in the Special Cost Escrow Account is less than 125% of future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future
costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When
there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow Account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow
Account generally will also be released when the balance in such account exceeds 125% of future Special Costs. In the first nine months of 2001, there was a net deposit of funds into the Special
Escrow Account. The Trust's share of the funds deposited was $315,509. This deposit was also primarily a result of an increase in the Working Interest Owner's current estimate of projected capital
expenditures of the Royalty Properties. In the first nine months of 2002, there was a net release of funds from the Special Cost Escrow Account. The Trust's share of the funds released was $411,575.
The release was made primarily due to a decrease in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties. As of September 30, 2002,
$5,041,112 remained in the Special Cost Escrow Account.

Chevron,
in its capacity as Managing General Partner, has advised the Trust that 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, 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.

Overview of Production, Prices and Net Proceeds

The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas recorded by the Working Interest
Owners for the Royalty Properties, as well as the Working Interest Owners' calculations of the net proceeds and the royalties paid to the Trust

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during the periods indicated. Net proceeds due to the Trust are calculated for each three month period commencing on the first day of February, May, August and November.

|                                                            |  | Royalty Properties
Three Months Ended
September 30,(1) |           
|----------------------------------------------------------- |  | ------------------------------------------------------ | ----------
|
|Crude oil and condensate (bbls)                             |  |                                                        | 217,656   
|Natural gas and gas products (Mcf)                          |  |                                                        | 214,123   
|Crude oil and condensate average price, per bbl             |  | $                                                      | 24.36     
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                      | 3.36      
|Crude oil and condensate revenues                           |  | $                                                      | 5,302,123 
|Natural gas and gas products revenues                       |  |                                                        | 677,847   
|Production expenses                                         |  |                                                        | (1,057,520
|Capital expenditures                                        |  |                                                        | (667,116  
|Undistributed Net Loss (Income)(2)                          |  |                                                        | (791,021  
|(Provision for) Refund of escrowed special costs            |  |                                                        | (686,260  
|                                                            |  |                                                        |           
|NET PROCEEDS                                                |  |                                                        | 2,778,054 
|Royalty interest                                            |  |                                                        | x25       
|                                                            |  |                                                        |           
|Partnership share                                           |  |                                                        | 694,513   
|Trust interest                                              |  |                                                        | x99.99    
|                                                            |  |                                                        |           
|Trust share                                                 |  | $                                                      | 694,444   
|                                                            |  |                                                        |           

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|                                                            |  | Royalty Properties
Nine Months Ended
September 30,(1) |           
|----------------------------------------------------------- |  | ----------------------------------------------------- | ----------
|
|Crude oil and condensate (bbls)                             |  |                                                       | 522,967   
|Natural gas and gas products (Mcf)                          |  |                                                       | 700,173   
|Crude oil and condensate average price, per bbl             |  | $                                                     | 21.92     
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                     | 2.55      
|Crude oil and condensate revenues                           |  | $                                                     | 11,465,209
|Natural gas and gas products revenues                       |  |                                                       | 1,781,947 
|Production expenses                                         |  |                                                       | (3,443,284
|Capital expenditures                                        |  |                                                       | (5,290,010
|Undistributed Net Loss (Income)(2)                          |  |                                                       | (187,477  
|Refund (Provision for) escrowed special costs               |  |                                                       | 1,646,302 
|                                                            |  |                                                       |           
|NET PROCEEDS                                                |  |                                                       | 5,972,687 
|Royalty interest                                            |  |                                                       | x25       
|Partnership share                                           |  |                                                       | 1,493,172 
|Trust interest                                              |  |                                                       | x99.99    
|                                                            |  |                                                       |           
|Trust share                                                 |  | $                                                     | 1,493,022 
|                                                            |  |                                                       |           

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Item 3. Quantitative and Qualitative Disclosure about Market Risk

Reference is made to Item 1 of this Form 10-Q.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures.The Corporate Trustee maintains disclosure controls and procedures designed
to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act of 1934, as amended, is recorded, processed, summarized and reported
within the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by
the Trust is accumulated and communicated by Chevron U.S.A Inc., as the managing general partner of the Partnership, and the working interest owners to JPMorgan Chase Bank, as Corporate Trustee
of the
Trust, and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

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Within
90 days of the date of this report, the Corporate Trustee carried out an evaluation of the Corporate Trustee's disclosure controls and procedures. Mike Ulrich, as Trust
Officer of the Corporate Trustee, has concluded that the controls and procedures are effective, while noting certain limitations on disclosure controls and procedures as set forth below.

Due
to the contractual arrangements of (i) the Trust Agreement, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding
information furnished by the working interest owners, there are certain potential weaknesses that may limit the effectiveness of disclosure controls and procedures established by the Corporate Trustee
or its employees and their ablility to verify the accounting of certain financial information. The contractual limitations creating potential weaknesses in disclosure controls and procedures may be
deemed to include:



The
Trustees do not intend to expand their responsibilities beyond those permitted or required by the Trust Agreement and those required under applicable law.

Changes in Internal Controls.To the knowledge of the Trustee, there have been no significant changes in the Trustee's
internal controls or in other factors that could significantly affect the Trustees' internal controls subsequent to the date the Trustee completed its evaluation. The Trustee notes for purposes of
clarification that it has no authority over, and makes no statement concerning, the internal controls of the working interest owners or the managing general partner of the Partnership.

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PART IIOTHER INFORMATION

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits

(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. JPMorgan Chase Bank is the
successor by mergers to the original name of the Corporate Trustee, Texas Commerce Bank, National Association).

|       |  |   |  |                                                                                                                                                                                                                                                                                                                              |  | SEC File or
Registration
Number |  | Exhibit
Number
|------ |  | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------- |  | --------------
|4(a)*  |  |  |  | Trust Agreement dated as of January 1, 1983, among Tenneco Offshore Company, Inc., Texas Commerce Bank National Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as individual
trustees (Exhibit 4(a) to Form 10-K for the year ended December 31, 1992 of TEL Offshore Trust) |  | 0-6910                          |  | 4(a)          
|4(b)*  |  |  |  | Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended December 31, 1992 of TEL Offshore
Trust)                                                                                          |  | 0-6910                          |  | 4(b)          
|4(c)*  |  |  |  | Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                                                          |  | 0-6910                          |  | 4(c)          
|4(d)*  |  |  |  | Amendments to TEL Offshore Trust Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                  |  | 0-6910                          |  | 4(d)          
|4(e)*  |  |  |  | Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                      |  | 0-6910                          |  | 4(e)          
|10(a)* |  |  |  | Purchase Agreement, dated as of December 7, 1984 by and between Tenneco Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K for year ended December 31, 1992, of TEL Offshore Trust)                                                                                                                     |  | 0-6910                          |  | 10(a)         
|10(b)* |  |  |  | Consent Agreement, dated November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)                                                                                                                                           |  | 0-6910                          |  | 10(b)         
|10(c)* |  |  |  | Assignment and Assumption Agreement, dated November 17, 1988, between Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)                                                                                                                    |  | 0-6910                          |  | 10(c)         
|10(d)* |  |  |  | Gas Purchase and Sales Agreement Effective September 1, 1993 between Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company (Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of TEL Offshore
Trust)                                                                                                |  | 0-6910                          |  | 10(d)         

(b) Reports on Form 8-K

No reports on Form 8-K were filed with the Securities and Exchange Commission during the third quarter of 2002.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.

| |  | TEL OFFSHORE TRUST
| |  | ------------------
| |  | By:               
| |  | By:               

Date:
November 14, 2001

The
Registrant, TEL Offshore Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures
are available and none have been provided.

CERTIFICATION

I, Mike Ulrich certify that:

1.    I
have reviewed this quarterly report on Form 10-Q of TEL Offshore Trust, for which JPMorgan Chase Bank acts as Corporate Trustee;

2.    Based
on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.    Based
on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial
condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this quarterly report;

4.    I
am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14),
or for causing such procedures to be established and maintained, for the registrant and have:



22

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5.    I
have disclosed, based on my most recent evaluation, to the registrant's auditors:



6.    I
have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal
controls subsequent to the date of my most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

In
giving the foregoing certifications in paragraphs 4, 5 and 6, I have relied to the extent I consider reasonable on information provided to me by the working interest owners and
the managing general partner of the TEL Offshore Trust Partnership, in which the registrant owns a 99.99% interest.

|Date: November 14, 2002 |  | /s/MIKE ULRICHMike Ulrich, Vice President
JPMorgan Chase Bank
|----------------------- |  | -------------------------------------------------------------

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