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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, 2003
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------

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:800-852-1422

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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).    Yes
    No X

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 14, 2003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  (Unaudited)

|                                                                                                                                        |  | September 30,
2003 |           | December 31,
2002
|--------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------ | --------- | -----------------
|Assets                                                                                                                                  |  |                    |           |                  
|Cash and cash equivalents                                                                                                               |  | $                  | 2,738,476 |                  
|Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,106,472 and $28,075,215, respectively |  |                    | 161,183   |                  
|                                                                                                                                        |  |                    |           |                  
|Total assets                                                                                                                            |  | $                  | 2,899,659 |                  
|                                                                                                                                        |  |                    |           |                  
|Liabilities and Trust Corpus                                                                                                            |  |                    |           |                  
|Distribution payable to Unit holders                                                                                                    |  | $                  | 1,374,065 |                  
|Reserve for future Trust expenses                                                                                                       |  |                    | 1,364,411 |                  
|Commitments and contingencies (Note 7)                                                                                                  |  |                    |           |                  
|Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)                                                        |  |                    | 161,183   |                  
|                                                                                                                                        |  |                    |           |                  
|Total liabilities and Trust corpus                                                                                                      |  | $                  | 2,899,659 |                  
|                                                                                                                                        |  |                    |           |                  

STATEMENTS OF DISTRIBUTABLE INCOME  (Unaudited)

|                                                         |  | Three Months Ended
September 30, |           | Nine Months Ended
September 30, |  
|-------------------------------------------------------- |  | -------------------------------- | --------- | ------------------------------- | -
|
|Royalty income                                           |  | $                                | 1,443,095 |                                 | $
|Interest income                                          |  |                                  | 1,767     |                                 |  
|                                                         |  |                                  |           |                                 |  
|                                                         |  |                                  | 1,444,862 |                                 |  
|(Increase)/Decrease in reserve for future Trust expenses |  |                                  | 0         |                                 |  
|General and administrative expenses                      |  |                                  | (145,797  | )                               |  
|Other-Texaco Settlement Agreement (Note 7)               |  |                                  | 75,000    |                                 |  
|                                                         |  |                                  |           |                                 |  
|Distributable income                                     |  | $                                | 1,374,065 |                                 | $
|                                                         |  |                                  |           |                                 |  
|Distributions per Unit (4,751,510 Units)                 |  | $                                | .289185   |                                 | $
|                                                         |  |                                  |           |                                 |  

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

1

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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               |  | $                                | 178,985    |                                 | $
|Distributable income                            |  |                                  | 1,374,065  |                                 |  
|Distribution payable to Unit holders            |  |                                  | (1,374,065 | )                               |  
|Amortization of net overriding royalty interest |  |                                  | (17,802    | )                               |  
|                                                |  |                                  |            |                                 |  
|Trust corpus, end of period                     |  | $                                | 161,183    |                                 | $
|                                                |  |                                  |            |                                 |  

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.

On
June 6, 2003 Anadarko Petroleum Corporation ("Anadarko") acquired, among other interests, a 25% Working Interest in the East Cameron 354 field subject to a 25% Net Profit
Interest property from Amerada effective April 1, 2003. As a result of this transaction, Anadarko replaced Amerada as the Working Interest Owner of East Cameron 354 effective July 1,
2003 and also assumed Amerada's obligations under the Conveyance with respect to said property.

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

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Cameron 371/381
from December 1, 1994 until May 1, 2002; SONAT with respect to East Cameron 354 for periods beginning on or after October 1, 1995; Amoco with respect to
Eugene Island 367 for periods beginning on or after October 1, 1995; Amerada with respect to East Cameron 354 for periods beginning on or after January 1, 1998; Chevron
with respect to West Cameron 643 and East Cameron 371/381 on and after May 1, 2002; and Anadarko with respect to East Cameron 354 on and after July 1, 2003.

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, 2002.

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 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

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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.

In
June 2001, FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which is effective for fiscal years beginning after June 15, 2002. SFAS
No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated assets retirement costs. The adoption of
SFAS No. 143 did not have a material impact on our financial position, distributable income or distributions.

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 special cost escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. 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 2003, there was a net deposit of funds into the Special Cost Escrow Account. The Trust's share of the funds deposited was $3,740,652. This deposit was
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, 2003, $8,482,007 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 Trust 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 at September 30, 2003 was $1,364,411. The amount of $28,194 was released to Unit
holders in the first quarter of 2003. The reserve amount at December 31, 2002 was $1,392,605. The amount of $205,287 was withheld from Unit holders in the second quarter of 2002 to maintain the
cash reserve.

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, which was recovered entirely from the Trust by the Working Interest Owner prior to the second quarter of 2003.

The
Working Interest Owners have advised the Trust that, although they believe 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 Trust alleged that TEPI improperly reduced the percentage of Net Proceeds payable to
the Trust and improperly deducted from Gross Proceeds certain costs that the Trust believed were attributable to TEPI's separate operations on an offsetting lease. In connection with the foregoing
litigation, TEPI asserted a counterclaim for overpayment of $880,632 prior to and during the third quarter of 1999. TEPI claimed that these costs should have been allocated to the Trust. During the
third quarter of 2003, the Trust entered into a Settlement Agreement and Mutual Release with TEPI pursuant to which TEPI agreed to pay the Trust $75,000. Both of the parties agreed to file a joint
motion to dismiss all claims and counterclaims relating to the lawsuit and each party agreed to release the other party from all claims and counterclaims relating to the lawsuit.

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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.

Financial Review

Three Months Ended September 30, 2003 and 2002

Distributions to the Unit holders for the three months ended September 30, 2003 amounted to $1,374,065 or $.289185 per Unit as compared to $617,102 or $.129875
per Unit for the same period in 2002. The increase in distributable income for the third quarter of 2003 was primarily due to increases in both oil and gas prices and production volumes, as described
below.

Crude
oil and condensate revenues increased 100% to $10,633,848 in the third quarter of 2003 from $5,302,123 in the third quarter of 2002 due to a 71% increase in production volumes and
a 17% increase in the average price of crude oil and condensate from $24.36 per barrel in the third quarter of 2002 to $28.62 in the same period in 2003. Oil volumes during the third quarter of 2003
totaled 371,595 barrels, compared to 217,656 barrels of oil produced in the third quarter of 2002. The higher oil volumes were primarily attributable to increases in Eugene Island 339 and Ship
Shoal 182/183.

Gas
revenues increased 244% to $2,333,939 in the third quarter of 2003 from $677,847 in the third quarter of 2002, primarily due to a 144% increase in gas volumes to 448,172 Mcf
in the third quarter of 2003 from 183,435 Mcf in the third quarter of 2002. Additionally, the average price received for natural gas increased 51% to $5.07 per Mcf in the third quarter of 2003
from $3.36 per Mcf on the third quarter of 2002. The higher gas volumes were primarily due to new wells on Eugene Island 339, combined with tubing workovers and stimulation on West
Cameron 643 and Ship Shoal 182/183.

The
Trust's share of capital expenditures increased in the third quarter of 2003, to $1,156,265 as compared to $667,116 in the third quarter of 2002. The higher capital expenditures in
the third quarter of 2003 were due primarily to drilling projects and hurricane repairs on Ship Shoal 182/183.

For
the third quarter of 2003, the Trust's share of undistributed net income was $0. Undistributed net income represents positive Net Proceeds, generated during the respective period,
that were applied to an existing loss carryforward. An undistributed net loss is carried forward and offset, in future periods, by positive Net Proceeds earned by the related Working Interest
Owner(s).

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In
the third quarter of 2003, there was a net deposit of funds into the Special Cost Escrow Account. The Trust's share of the funds deposited was approximately $1,225,110, compared to a
net deposit of funds into the Special Cost Escrow Account of $171,565 by the Trust in the third quarter of 2002. 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, 2003 and 2002

Distributions to Unit holders for the nine months ended September 30, 2003 amounted to $3,046,252 or $.641112 per Unit, as compared to $982,043 or $.206680 per
Unit for the same period in 2002. The increase in distributable income for the first nine months of 2003 was primarily due to increased oil and gas prices and increased production volumes, as
described below.

Crude
oil and condensate revenues increased $16,944,591, or 148%, to $28,409,800 in the first nine months of 2003 as compared to $11,465,209 in the same period in 2002, primarily due to
an 84% increase in the crude oil and condensate volumes from the first nine months of 2002 to the same period in 2003. Crude oil volumes increased from 522,968 barrels in the first nine months of 2002
to 961,320 barrels in the first nine months of 2003. The increase in crude oil and condensate volumes along with the 35% increase in the average price of crude oil and condensate from $21.92 per
barrel in the nine months ended September 30, 2002 to $29.55 per barrel in the same period in 2003 account for the increase in revenues.

Gas
revenues increased $6,673,604 or 375%, to $8,541,564 in the nine months ended September 30, 2003 from $1,781,947 in the same period in 2002, primarily due to a 116% increase
in the average price received for natural gas to $5.52 per Mcf in the nine months ended September 30, 2003 from $2.55 per Mcf in the nine months ended September 30, 2002. This increase
in average price, together with a 121% increase in gas volumes to 1,546,754 Mcf in the first nine months of 2003 from 700,173 Mcf for the same period in 2002, accounts for the increase
in gas revenues.

The
Trust's share of capital expenditures decreased $680,669, or 13% from $5,290,010 in the nine months ended September 30, 2002 to $4,609,341 in the same period in 2003. This
decrease was primarily due to a developmental well drilling project during 2002 on the Ship Shoal 182/183 property, offset by another drilling project on Ship Shoal 182/183 during 2003.

In
the first nine months of 2003, there was a deposit of funds into the Special Cost Escrow Account. The Trust's share of the funds deposited was $3,740,198 compared to a net release of
funds from the Special Cost Escrow Account of $411,575 net release to the Trust in the first nine months of 2002. The Special Cost Escrow is set aside for estimated expenditures as provided for in the
Conveyence. For additional information to the Special Cost Escrow see "Special Cost Escrow Account" below.

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 2003 is $1,364,411. The reserve amount at December 31, 2002 was $1,392,605.

10

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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, 2003 and 2002

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

Ship
Shoal 182/183 crude oil revenues increased from $2,172,134 in the third quarter of 2002 to $4,528,163 in the third quarter of 2003, primarily due to increases in both
production and prices. Crude oil production increased from 88,818 barrels in the third quarter of 2002 to 163,498 barrels in the third quarter of 2003. The increase in crude oil production was due
primarily to production from the I-4 well, which came online in January of 2003. Furthermore, there was an increase in the average price of crude oil from $24.46 per barrel in the third quarter of
2002 to $27.70 per barrel for the same period in 2003. Gas revenues increased from $110,969 in the third quarter of 2002 to $690,072 in the third quarter of 2003 primarily due to an increase in both
production and prices. Gas volumes increased from 30,264 Mcf in the third quarter of 2002 to 135,252 Mcf in the third quarter of 2003. The average natural gas sales price increased
significantly from $3.67 per Mcf in the third quarter of 2002 to $5.23 per Mcf in the third quarter of 2003. The increase in gas volumes was primarily due to production from the I-4 well that came
online in January of 2003. Capital expenditures increased from $242,681 in the third quarter of 2002 to $945,493 in the third quarter of 2003 due primarily to the I-4 well drilling project. Operating
expenses decreased slightly from $432,492 in the third quarter of 2002 to $409,810 for the same period in 2003.

Eugene
Island 339 crude oil revenues increased from $2,969,849 in the third quarter of 2002 to $5,852,916 in the third quarter of 2003, primarily due to significant increases in
both prices and production. The average price of crude oil increased from $24.23 per barrel in the second quarter of 2002 to $29.40 per barrel in the second quarter of 2003. Crude oil production
increased from 122,576 barrels in the third quarter of 2002 to 199,088 barrels in the third quarter of 2003 primarily due to the C-5 well coming online and revisions made by Chevron in the third
quarter 2003. Gas revenues increased from $272,483 in the third quarter of 2002 to $629,719 in the third quarter of 2003, primarily due to a production increase from 94,137 Mcf in the third quarter
2002 to 147,486 Mcf in the third quarter 2003. The average natural gas sales price increased from $2.89 per Mcf in the third quarter of 2002 to $4.27 per Mcf in the third quarter of 2003. Capital
expenditures decreased to $141,578 in the third quarter of 2003 from $350,456 in the third quarter of 2002 due to B-7 and B-9 well expenses that were incurred during 2002. Operating expenses decreased
from $192,029 in the third quarter of 2002 to $136,700 in the third quarter of 2003 due to understated expenses in the second quarter of 2002.

West
Cameron 643 gas revenues increased from $63,817 in the third quarter of 2002 to $720,459 in the third quarter of 2003, primarily due to an increase in gas volumes from
17,628 Mcf in the third quarter of 2002 to 133,060 Mcf in the third quarter of 2003 and the significant increase in the average price received for natural gas from $3.62 per Mcf in the
third quarter of 2002 to $5.41 per Mcf in the third quarter of

11

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2003.
The increase in gas volumes was due primarily to the A-14 well being shut in during the third quarter of 2002 and an increase in the A-17 volumes during the third quarter of 2003 due to a well
choke adjustment. Operating expenses decreased from $217,732 in the third quarter of 2002 to $162,336 for the same period in 2003. Capital expenditures decreased slightly from $44,699 in the third
quarter of 2002 to $27,238 in the third quarter of 2003.

East
Cameron 371/381 crude oil revenues decreased from $25,202 in the third quarter of 2002 to $10,491 in the third quarter of 2003, primarily due to a decrease in crude oil production
from 957 barrels in the third quarter of 2002 to 341 barrels in the same period in 2003. This production decline was partially offset by an increase in the average price received of $26.33 per barrel
in the third quarter of 2002 to $30.76 per barrel in the third quarter of 2003. Gas revenues decreased from $59,427 in the third quarter of 2002 to $32,347 in the third quarter of 2003. This decrease
was primarily due to a decrease in gas volumes from 19,944 Mcf in the third quarter of 2002 to 6,135 Mcf in the third quarter of 2003. This volume decrease was partially offset by an
increase in the average natural gas sales price from $2.98 per Mcf in the third quarter of 2002 to $5.27 per Mcf in the third quarter of 2003. Operating expenses decreased from $25,683 in the third
quarter of 2003 to $4,267 in the third quarter of 2003. Capital expenditures increased from $0 in the third quarter of 2002 to $611 in the third quarter of 2003.

Chevron
has advised the Trust that from April 2003 forward, a new division of Chevron called "ChevronTexaco Natural Gas" began directly marketing most of Chevron's owned and controlled
production to various third-party purchasers under a mix of term and spot agreements. A portion of the gas is used in Chevron or joint venture facilities, consistent with Chevron's objectives of
optimizing certainty of flow and achieving the best netbacks from creditworthy counterparties. The gas that is used in ChevronTexaco owned facilities or otherwise disposed of in a non-arm's length
transaction is valued at current market prices based on the weighted average proceeds from comparable arms' length sales in the same area, arm's length purchases Chevron made in the same area, and/or
applicable published index prices.

Nine Months Ended September 30, 2003 and 2002

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

Ship
Shoal 182/183 crude oil revenues increased from $6,467,828 in the first nine months of 2002 to $13,809,481 in the first nine months of 2003, primarily due to an increase in the
average price of crude oil from $21.68 per barrel in the first nine months of 2002 to $30.04 per barrel in the first nine months of 2003. Crude oil production increased from 298,282 barrels in the
nine months of 2002 to 459,736 barrels in the first nine months of 2003, primarily as a result of production from the I-4 well, which came online in January 2003. Gas revenues increased from $501,269
in the first nine months of 2002 to $2,225,994 in the first nine months of 2003 primarily due to a significant increase in the average natural gas sales price from $2.58 per Mcf in the first nine
months of 2002 to $5.45 per Mcf in the first nine months of 2003. Gas volumes increased from 194,275 Mcf in the first nine months of 2002 to 408,452 Mcf in the first nine months of 2003,
primarily as a result of production from the I-4 well, which came online in January 2003. Capital expenditures increased from $3,886,085 in the first nine months of 2002 to $4,137,767 in the same
period of 2003 primarily due to development of I-4. Operating expenses decreased from $1,193,286 for the first nine months of 2002 to $1,172,953 for the first nine months of 2003.

Eugene
Island 339 crude oil revenues increased from $4,551,470 in the first nine months of 2002 to $13,884,063 in the first nine months of 2003, primarily due to increases in both prices
and production.

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Crude
oil production increased from 204,498 barrels in the first nine months of 2002 to 478,395 barrels in the first nine months of 2003 primarily due to increased production on the B-7 and B-1 wells,
C-5 well coming online and revisions made by Chevron in the third quarter 2003, partially offset by field declines. The average price of crude oil increased from $22.26 per barrel in the first nine
months of 2002 to $29.02 per barrel in the first nine months of 2003. Gas revenues increased from $360,405 in the first nine months of 2002 to $2,802,367 in the first nine months of 2003, primarily
due to a significant increase in production from 120,595 Mcf for the first nine months of 2002 to 533,093 Mcf for the same period in 2003. Capital expenditures decreased from $853,731 in the first
nine months of 2002 to $243,039 in the first nine months of 2003. This decrease was due primarily to the B-7 sidetrack workover, B-9 well expenses and inspection program done in 2002. Operating
expenses decreased from $415,593 for the first nine months of 2002 to $357,379 for the first nine months of 2003.

West
Cameron 643 gas revenues increased from $165,474 in the first nine months of 2002 to $2,710,994 in the first nine months of 2003, primarily due to an increase in gas volumes from
59,107 Mcf in the first nine months of 2002 to 476,615 Mcf for the same period in 2003. The average natural gas sales price increased from $2.80 per Mcf in the first nine months of 2002
to $5.69 per Mcf in the first nine months of 2003. Operating expenses decreased from $628,188 in the first nine months of 2002 to $512,390 for the first nine months of 2003. Capital expenditures
decreased from $474,720 in the first nine months of 2002 to $159,057 in the first nine months of 2003.

East
Cameron 371/381 crude oil revenues decreased from $68,786 in the first nine months of 2002 to $61,808 in the first nine months of 2003 due in part to a decrease in crude oil
production from 2,968 barrels in the first nine months of 2002 to 1,929 barrels in the first nine months of 2003. The decrease in production was offset by an increase in the average price of crude oil
from $23.18 per barrel in the first nine months of 2002 to $32.04 per barrel for the same period in 2003. Gas revenues decreased from $175,616 in the first nine months of 2002 to $149,358 in the first
nine months of 2003, due in part to a decrease in gas volumes from 65,035 Mcf in the first nine months of 2002 to 29,988 Mcf in the first nine months of 2003. The decrease in gas volumes was offset by
an increase in the average natural gas sales price from $2.70 per Mcf in the first nine months of 2002 to $4.98 per Mcf in the first nine months of 2003. Operating expenses decreased from $128,090 in
the first nine months of 2002 to $21,686 in the first nine months of 2003. Capital expenditures increased from $0 in the first nine months of 2002 to $5,697 in the first nine months of 2003.

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, 2002 future
net revenues attributable to the Trust's royalty interests approximated $22.1 million. Such reserve study also indicates that approximately 60% 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

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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 2002 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 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 2003, there was a net deposit of funds into the Special Escrow Account. The Trust's share of the funds deposited was $3,740,198. The deposit
was 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, 2003, $8,484,008 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)                             |  |                                                        | 371,595   
|Natural gas and gas products (Mcf)                          |  |                                                        | 465,088   
|Crude oil and condensate average price, per bbl             |  | $                                                      | 28.62     
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                      | 5.07      
|Crude oil and condensate revenues                           |  | $                                                      | 10,633,848
|Natural gas and gas products revenues                       |  |                                                        | 2,333,939 
|Production expenses                                         |  |                                                        | (1,138,123
|Capital expenditures                                        |  |                                                        | (1,156,265
|Undistributed Net Income(2)                                 |  |                                                        | 0         
|(Provision for) escrowed special costs                      |  |                                                        | (4,900,439
|                                                            |  |                                                        |           
|Net Proceeds                                                |  |                                                        | 5,772,960 
|Royalty interest                                            |  |                                                        | x25       
|                                                            |  |                                                        |           
|Partnership share                                           |  |                                                        | 1,443,240 
|Trust interest                                              |  |                                                        | x99.99    
|                                                            |  |                                                        |           
|Trust share                                                 |  | $                                                      | 1,443,095 
|                                                            |  |                                                        |           

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15

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|                                                            |  | Royalty Properties
Nine Months Ended
September 30,(1) |            
|----------------------------------------------------------- |  | ----------------------------------------------------- | -----------
|
|Crude oil and condensate (bbls)                             |  |                                                       | 961,320    
|Natural gas and gas products (Mcf)                          |  |                                                       | 1,563,670  
|Crude oil and condensate average price, per bbl             |  | $                                                     | 29.55      
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                     | 5.52       
|Crude oil and condensate revenues                           |  | $                                                     | 28,409,800 
|Natural gas and gas products revenues                       |  |                                                       | 8,541,564  
|Production expenses                                         |  |                                                       | (3,413,783 
|Capital expenditures                                        |  |                                                       | (4,609,489 
|Undistributed Net Loss (Income)(2)                          |  |                                                       | (43,468    
|Refund (Provision for) escrowed special costs               |  |                                                       | (14,962,608
|                                                            |  |                                                       |            
|Net Proceeds                                                |  |                                                       | 13,922,164 
|Royalty interest                                            |  |                                                       | x25        
|Partnership share                                           |  |                                                       | 3,480,541  
|Trust interest                                              |  |                                                       | x99.99     
|                                                            |  |                                                       |            
|Trust share                                                 |  | $                                                     | 3,480,192  
|                                                            |  |                                                       |            

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Item 3. Quantitative and Qualitative Disclosure about Market Risk

No material changes have occurred since our Audit Report on Form 10-K for the year-ended December 31, 2002. Reference is also made to Note 2 of the Notes
to the Financial Statements included in 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.

As
of the end of the period covered by 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

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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 ability 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.

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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.

Changes in internal control over financial reporting.The Trustee has not identified any changes in the Trust's internal
control over financial reporting during the Trust's last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial
reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of the working interest
owners or the managing general partner of the Partnership.

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PART IIOTHER INFORMATION

Item 1. Legal Proceedings.

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 Trust alleged that TEPI improperly reduced the percentage of Net Proceeds payable to
the Trust and improperly deducted from Gross Proceeds certain costs that the Trust believed were attributable to TEPI's separate operations on an offsetting lease. In connection with the foregoing
litigation, TEPI asserted a counterclaim for overpayment of $880,632 prior to and during the third quarter of 1999. TEPI claimed that these costs should have been allocated to the Trust. During the
third quarter of 2003, the Trust entered into a Settlement Agreement and Mutual Release with TEPI pursuant to which TEPI agreed to pay the Trust $75,000. Both of the parties agreed to file a joint
motion to dismiss all claims and counterclaims relating to the lawsuit and each party agreed to release the other party from all claims and counterclaims relating to the lawsuit.

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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)         
|31     |  |  |  | Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                            |  |                                 |  |               
|32     |  |  |  | Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                            |  |                                 |  |               

(b) Reports on Form 8-K

Current reports on Form 8-K were filed with the Securities and Exchange Commission on September 19, 2003.

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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, 2003

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.

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