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 June 30, 2004
|- |  | ------------------------------------------------------------------------------------------------------------------------------------

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

76-6004064(State of Incorporation,
or Organization)

(I.R.S. Employer
Identification No.)JPMorgan Chase Bank
Institutional Trust Services
700 Lavaca StreetAustin, Texas

78701(Address of Principal
Executive Offices)

(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
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 August 13, 20044,751,510 Units of Beneficial Interest in TEL Offshore Trust.



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PART IFINANCIAL INFORMATION

Item 1. Financial Statements.

TEL OFFSHORE TRUST  STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS  (Unaudited)

|                                                                                                                                        |  | June 30,
2004 |           | December 31,
2003
|--------------------------------------------------------------------------------------------------------------------------------------- |  | ------------- | --------- | -----------------
|Assets                                                                                                                                  |  |               |           |                  
|Cash and cash equivalents                                                                                                               |  | $             | 1,081,415 |                  
|Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,126,368 and $28,113,036, respectively |  |               | 124,601   |                  
|                                                                                                                                        |  |               |           |                  
|Total assets                                                                                                                            |  | $             | 1,206,016 |                  
|                                                                                                                                        |  |               |           |                  
|Liabilities and Trust Corpus                                                                                                            |  |               |           |                  
|Distribution payable to Unit holders                                                                                                    |  | $             | 0         |                  
|Reserve for future Trust expenses                                                                                                       |  |               | 1,081,415 |                  
|Commitments and contingencies                                                                                                           |  |               |           |                  
|Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)                                                        |  |               | 124,601   |                  
|                                                                                                                                        |  |               |           |                  
|Total liabilities and Trust corpus                                                                                                      |  | $             | 1,206,016 |                  
|                                                                                                                                        |  |               |           |                  

STATEMENTS OF DISTRIBUTABLE INCOME  (Unaudited)

|                                              |  | Three Months Ended
June 30, |          | Six Months Ended
June 30, |  
|--------------------------------------------- |  | --------------------------- | -------- | ------------------------- | -
|
|Royalty income (See Note 4)                   |  | $                           | 83,857   |                           | $
|Interest income                               |  |                             | 1,452    |                           |  
|                                              |  |                             |          |                           |  
|                                              |  |                             | 85,309   |                           |  
|Decrease in reserve for future Trust expenses |  |                             | 56,341   |                           |  
|General and administrative expenses           |  |                             | (141,650 | )                         |  
|                                              |  |                             |          |                           |  
|Distributable income                          |  | $                           | 0        |                           | $
|                                              |  |                             |          |                           |  
|Distributions per Unit (4,751,510 Units)      |  | $                           | .000000  |                           | $
|                                              |  |                             |          |                           |  

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
June 30, |         | Six Months Ended
June 30, |  
|----------------------------------------------- |  | --------------------------- | ------- | ------------------------- | -
|
|Trust corpus, beginning of period               |  | $                           | 141,287 |                           | $
|Distributable income                            |  |                             | 0       |                           |  
|Distribution payable to Unit holders            |  |                             | 0       |                           |  
|Amortization of net overriding royalty interest |  |                             | (16,686 | )                         |  
|                                                |  |                             |         |                           |  
|Trust corpus, end of period                     |  | $                           | 124,601 |                           | $
|                                                |  |                             |         |                           |  

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 of 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 these 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 these 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 these 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 this property.

Effective
January 1, 2000 PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon Energy Production Company L.P. ("Devon"). As a result of such 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 these properties.

On
October 9, 2001, a wholly owned subsidiary of Chevron Corporation, a Delaware corporation, merged (the "Merger") with and into Texaco Inc., a Delaware corporation
("Texaco"), pursuant to an Agreement and Plan of Merger, dated as of October 15, 2000. 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" in connection with the Merger (ChevronTexaco Corporation is referred to herein as "ChevronTexaco"). Accordingly, the properties
referred to herein by Chevron and Texaco are each now controlled by subsidiaries 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
profits interest 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 (Tenneco Exploration, Ltd. through October 31, 1986; Tenneco for periods from October 31, 1986 until November 18,
1988; Chevron with respect to all Royalty Properties for periods from November 18, 1988 until October 30, 1992, and with respect to all Royalty Properties

4

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except
East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until December 1, 1994, and with respect to the same properties
except West Cameron 643 thereafter; PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene/Devon Island 208 for periods from October 30, 1992 until
October 1, 1995, and with respect to Eugene Island 348 and Eugene Island 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron 371/381 for periods beginning on or after
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; 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 merger
to the original name of the Corporate Trust, 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, 2003.

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

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and
administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net 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
decrease in reserve for future Trust expenses includes both decreases of amounts deemed necessary by the Trustees and related distributions, as well as amounts paid from the reserve
during periods when the Trust has insufficient income to pay Trust expenses.

The
Trust reviews the net overriding royalty interest in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not
be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset
and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss is recognized to write down the asset to its estimated fair value. Preparation of
estimated expected future cash flows is
inherently subjective and is based on the Corporate Trustee'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, such as
the loss carryforward described in Note 4.

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 Trust's 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.

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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" means 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 Escrow account (See
Note 6) 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.

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. Such distributions are referred to as "distributable
income." 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.

During
the quarter ended March 31, 2004, a Working Interest Owner made certain negative adjustments to previously reported Net Proceeds (See Note 5). As a result of these
negative adjustments, the Trust at March 31, 2004 had a loss carryforward of $3,307,628. In the second quarter of 2004, Net Proceeds were offset by the loss carryforward of $3,307,628 with a
resulting loss carryforward balance of $0 at June 30, 2004. Royalty income to the Trust in the second quarter of 2004 was $83,857; however, no distributable income will be available to Unit
holders until the Trust recoups expenses being paid from the reserve for Trust expense that the Trustees have established for anticipated future expenses.

Note 5  Negative Adjustments

During the quarter ended March 31, 2004, a Working Interest Owner informed the Trust that it had made errors in prior periods which resulted in prior
period Net Proceeds being overstated. This Working

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Interest
Owner, Chevron, which is also the Managing General Partner, has advised the Trust that these errors consisted of:



The
Trust recorded the adjustments during the first quarter of 2004, which resulted in a loss carryforward of $3,307,628 as of March 31, 2004. In the second quarter of 2004, Net
Proceeds were offset by the loss carryforward of $3,307,628, with a resulting loss carryforward balance of $0 at June 30, 2004.

Note 6  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 Royalty 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 profits interest. 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 profits interest 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 estimated 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 estimated future Special Costs. In the first six months of 2004, there was a net release of funds from the Special Cost Escrow account. The Trust's
share of the funds released was approximately $1,189,581. The release was primarily due to a decrease of $3,755,526 in projected special costs for capital expenditures. In

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the
first six 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 approximately $2,515,542. As of June 30, 2004,
$7,426,105 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 which such deposits are made, including the possibility that no Royalty income would be received in such periods.

Note 7  Reserve For Future Trust Expenses

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 for 2003 was $1,364,411. The reserve amount for 2004 was calculated to be $1,229,475.
During the first six months of 2004, the Trust used $199,131 from the Trust's cash reserve account to pay the Trust's general and administrative expenses, when insufficient Royalty income was received
by the Trust, reducing the reserve amount held by the Trust to $1,081,415 as of June 30, 2004. Amounts will be withheld to increase this reserve to its calculated balance when the Trust
receives Royalty income in future periods. As of June 30, 2004, the Trust expense deficit was $148,060, which will funded prior to future distributions.

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

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.

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 June 30, 2004 and 2003

There were no distributions for the three months ended June 30, 2004. In the second quarter of 2004, Net Proceeds were offset by the loss carryforward of
$3,307,628 existing at the end of the first quarter of 2004, with a resulting loss carryforward balance of $0 at June 30, 2004 and Royalty income of only $83,857. General and administrative
expenses exceeded Royalty income and interest income, which required the Trustee to use $56,341 from the reserve for Trust expenses. No distributable income will be available to Unit holders until the
Trust recoups expenses being paid from the reserve for Trust expenses that the Trustees have established for anticipated future expenses. See Note 7 of the notes to financial statements in this
Form 10-Q. Distributions to Unit holders for the three months ended June 30, 2003 amounted to $1,577,454 or $.331990 per Unit.

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Gas
revenues increased $224,842, or 5%, to $4,802,412 in the second quarter of 2004 from $4,577,570 in the second quarter of 2003, due to an increase in gas volumes of 11% to 831,791 Mcf
in the second quarter of 2004 from 747,306 Mcf in the second quarter of 2003, offset by a 6% decrease in the average price received for natural gas to $5.77 per Mcf in the second quarter of 2004 from
$6.13 per Mcf in the second quarter of 2003. Gas products revenue increased $702,470, or 1,066%, to $768,386 in the second quarter of 2004 from $65,916 in the second quarter of 2003, due primarily to
an increase in production volume of 1,270,869 Mcf, or 1,080%, to 1,388,572 Mcf in the second quarter of 2004 from 117,703 Mcf in the second quarter of 2003.

Crude
oil and condensate revenues decreased $1,028,925, or 10%, to $8,987,940 in the second quarter of 2004 as compared to $10,016,865 in the second quarter of 2003, due to a 14%
decrease in crude oil and condensate volume to 263,463 barrels in the first quarter of 2004 from 307,463 barrels in the second quarter of 2003. The decrease is partially offset by a 5% increase in the
average price of crude oil and condensate to $34.11 per barrel in the second quarter of 2004 from $32.58 per barrel in the second quarter of 2003.

The
Trust's share of capital expenditures increased approximately $2,662,116, from ($2,014,037) in the second quarter of 2003 to $648,079 in the second quarter of 2004. During the second
quarter of 2003, negative adjustments relating to the drilling of the I-4 well were recorded which caused the negative balance. The increase in capital expenditures in the second quarter
of 2004 is a result of higher than estimated costs relating to the C-platform upgrade.

The
Trust's share of undistributed net income was $13,231,454 in the second quarter of 2004. As discussed above, Net Proceeds were offset by the net loss carryforward of $3,307,628
during the second quarter of 2004, with a resulting loss carryforward balance of $0 as of June 30, 2004. In addition, Royalty income and interest income did not exceed Trust expenses during the
quarter, resulting in a use of funds from the reserve for Trust expenses. See "Reserve for Future Trust Expenses" below. For the second quarter of 2003, the Trust's share of undistributed
net income was $8,241. Undistributed net loss represents negative Net Proceeds generated during the respective period. Undistributed net income represents positive Net Proceeds, generated during the
respective period that was 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).

In
the second quarter of 2004, there was a net refund of funds from the Special Cost Escrow account. The Trust's share of the funds refunded was approximately $336,232. The refund was
primarily a result of a decrease in Royalty income that was caused by the negative adjustments relating to prior periods, as discussed below. In the second quarter of 2003, there was a net deposit of
funds into the Special Cost Escrow account. The Trust's share of the funds deposited during this quarter was approximately $2,094,143. As of June 30, 2004, $7,426,105 remained in the Special
Cost Escrow account. 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.

Six Months Ended June 30, 2004 and 2003

Gas revenues increased $132,958, or 2%, to $6,254,570 in the first six months of 2004 from $6,121,612 for the same period in 2003, due to a 5% increase in the
average price received for natural gas to $5.96 per

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Mcf
in the first six months of 2004 from $5.69 per Mcf in the same period of 2003, which was partially offset by a decrease in gas volumes of 1% to 1,067,945 Mcf in the first six months of 2004 from
1,075,073 Mcf for the same period in 2003. Gas products revenue increased $673,367, or 783%, to $759,380 in the first six months of 2004 from $86,013 in the same period of 2003, due primarily to an
increase in production volume of 1,199,075 Mcf, or 729%, to 1,363,643 Mcf in the first six months of 2004 from 164,568 Mcf in the same period of 2003. The production for the first six months of 2004
includes negative adjustments resulting from the improper credits of production and revenues by Chevron.

Crude
oil and condensate revenues decreased $10,898,241, or 61%, to $6,857,710 in the first six months of 2004 as compared to $17,755,951 for the same period in 2003, due to a 71%
decrease in crude oil and condensate volume to 170,383 barrels in the first six months of 2004 from 589,725 barrels for the same period in 2003. The revenues and volumes for the first six months of
2004 include negative adjustments, as a result of the improper credits of production and revenues by Chevron, totaling 295,224 barrels recorded by the Trust in the first quarter of 2004. The decrease
is also affected by a 5% decrease in the average price of crude oil and condensate from $30.14 per barrel in the first six months of 2003 to $28.50 per barrel for the same period in 2004.

The
Trust's share of capital expenditures increased approximately $11,074,273, from $3,453,005 in the first six months of 2003 to $14,527,278 in the same period of 2004. The increase in
capital expenditures for the first six months of 2004 related primarily to drilling of the new Ship Shoal 182/183 F-3 well and the C-20 and C-21 wells on Eugene Island 339 and associated
platform upgrades, compared to capital expenditures for the same period in 2003, which related primarily to the new I-4 well and some residual costs from completion of I-2 and
I-3 wells on the Ship Shoal 182/183 property. The Trust recorded an adjustment of $2,026,684 in the first quarter of 2004, relating primarily to charges incurred in the fourth quarter of
2003. Adjustments to capital expenditures
are based on miscalculations and duplication of downward adjustments allocations on Ship Shoal 182/183 during the third and fourth quarters of 2003. These miscalculations and duplications are
reflected in the amounts provided.

The
Trust's share of undistributed net income was $1,356,586 in the first six months of 2004. As discussed above, Net Proceeds during the second quarter of 2004 were offset by the loss
carryforward of $3,307,863 existing as of March 31, 2004, resulting in a loss carryforward balance of $0 at June 30, 2004. For the first six months of 2003, the Trust's share of
undistributed net income was $43,468.

In
the first six months of 2004, there was a net refund of funds from the Special Cost Escrow account. The Trust's share of the funds refunded was approximately $1,189,581. In the first
six 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 approximately $2,515,542. As of June 30, 2004, $7,426,105
remained in the Special Cost Escrow account. 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.

Reserve for Future Trust Expenses

In accordance with the provisions of the Trust Agreement, generally all Royalty income 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 the first quarter of 1998, the Trust determined that
the Trust's cash reserve was sufficient at that time to

12

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provide
for future administrative expenses in connection with the winding up of the Trust. The Trust determined that a cash reserve equal to three times the average expenses of the Trust during each
of the past three years was sufficient at this time to provide for future administrative expenses in connection with the winding up of the Trust. The reserve amount for 2003 was $1,364,411. The
reserve amount for 2004 was calculated to be $1,760,592. During the first six months of 2004, the Trust used $282,996 from the Trust's cash reserve account to pay the Trust's general and
administrative expenses, when insufficient Royalty income was received by the Trust, reducing the reserve amount held by the Trust to $1,081,415 as of June 30, 2004. Amounts will be withheld to
increase this reserve to its calculated balance when the Trust receives Royalty income.

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 as well as capital expenditures by the Working Interest Owners that may or may not be included in the Special Cost Escrow account. 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 June 30, 2004 and 2003

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 $5,773,579 in the second quarter of 2003 to $4,300,079 in the second quarter of 2004, primarily due to a decrease in net crude oil
production from 168,424 barrels in the second quarter of 2003 to 123,819 in the second quarter of 2004. The decrease was partially offset by an increase in the average crude oil price from $34.28 per
barrel in the second quarter of 2003 to $34.73 per barrel for the same period in 2004. Gas revenues increased from $1,188,684 in the second quarter of 2003 to $3,361,078 in the second quarter of 2004
due to an increase in gas production from 197,141 Mcf in the second quarter of 2003 to 578,282 Mcf in the second quarter of 2004, which was partially offset by a decrease in the average natural gas
sales price from $6.03 per Mcf in the second quarter of 2003 to $5.81 per Mcf for the same period in 2004. The increase in gas volume primarily resulted from the addition of the F-3 well
in early January 2004. Capital expenditures increased from ($2,160,245) in the second quarter of 2003 to $82,763 in the second quarter of 2004. Operating expenses increased from $378,446 in the
second quarter of 2003 to $746,914 for the same period in 2004.

Eugene
Island 339 net crude oil revenues increased from $3,906,560 in the second quarter of 2003 to $4,552,755 for the same period in 2004 due to an increase in volumes from 129,307 in
the second quarter of 2003 to 135,791 barrels in the second quarter of 2004. In addition, the average crude oil price increased from $30.21 per barrel in the second quarter of 2003 to $33.53 per
barrel in the second quarter of 2004. Gas revenues decreased from $1,838,895 in the second quarter 2003 to $938,881 in the second quarter of 2004, primarily due to a decrease in natural gas volumes
from 325,003 Mcf in the first quarter of 2003 to 152,687 Mcf in the second quarter of 2004. Capital expenditures increased from $66,796 in the second

13

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quarter
of 2003 to $524,409 in the second quarter of 2004, due to various capital projects that were completed in the second quarter of 2004, primarily $447,000 of additional costs to upgrade the C
platform facilities. Operating expenses increased from $107,827 in the second quarter of 2003 to $358,010 in the second quarter of 2004.

West
Cameron 643 gas revenues decreased from $1,269,902 in the second quarter of 2003 to $398,406 in the second quarter of 2004. This is due to a decrease in gas volumes from 183,343 Mcf
in the second quarter of 2003 to 72,970 Mcf for the same period in 2004. The decrease in volumes was primarily due to diminishing returns from wells. Gas prices increased $0.96 per Mcf from $4.50 per
Mcf in the second quarter of 2003 to $5.46 per Mcf in the second quarter of 2004. Operating expenses decreased from $120,358 in the second quarter of 2003 to $84,993 for the same period in 2004, and
capital expenditures decreased from $61,490 in the second quarter of 2003 to $2,066 for the same period in 2004, due to production decreases.

East
Cameron 371/381 crude oil revenues decreased from $23,064 in the second quarter of 2003 to $9,205 in the second quarter of 2004, primarily due to the decrease in crude oil
production from 668 barrels in the second quarter of 2003 to 242 barrels for the same period in 2004. The decrease was partially offset by an increase in the average crude oil price from $34.53 per
barrel in the second quarter of 2003 to $38.07 per barrel in the second quarter of 2004. Gas revenues decreased from $58,152 in the second quarter of 2003 to $28,230 in the second quarter of 2004.
This is due to a decreases in both gas volumes and prices. Gas volumes decreased from 8,462 Mcf in the second quarter of 2003 to 5,008 Mcf for the same period in 2004. The average price received for
natural gas decreased from $6.87 per Mcf in the second quarter of 2003 to $5.64 per Mcf in the second quarter of 2004. Capital expenditures were $577 in the second quarter of 2003 and were $1,283 in
the second quarter of 2004. Operating expenses increased from ($5,213) in the second quarter of 2003 to $11,109 in the second quarter of 2004.

Six Months Ended June 30, 2004 and 2003

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

During
the first quarter of 2004, a Working Interest Owner informed the Trust that it had made errors in prior periods which resulted in prior periods Net Proceeds being overstated. This
Working Interest Owner, Chevron, which is also the Managing General Partner, has advised the Trust that these errors consisted of:



The
gross adjustments, before the Special Cost Escrow account adjustment, were $10,911,175 or a $2,727,521 increase to $3,307,628 in the losses to be carried forward and netted against
future Net Proceeds earned by the Trust on Royalty Properties operated by this Working Interest Owner as of

14

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March 31,
2004. In the second quarter of 2004, Net Proceeds of $3,307,628 were used to offset the loss carryforward of $3,307,628, resulting in a loss carryforward balance of $0 at
June 30, 2004; however, no distributable income will be available to Unit holders until the Trust recoups expenses being paid from the reserve for Trust expenses that the Trustees have
established for anticipated future expenses. See Note 7 of the notes to financial statements in this Form 10-Q.

Ship
Shoal 182/183 crude oil revenues decreased from $9,281,318 in the first six months of 2003 to $6,707,654 in the same period in 2004, primarily due to a decrease in net crude oil
production from 296,238 barrels in the first six months of 2003 to 203,234 in the same period of 2004, which includes a negative retroactive adjustment of 44,214 barrels relating to the fourth quarter
of 2003 discussed above. The decrease was partially offset by an increase in the average crude oil price from $31.33 per barrel in the first six months of 2003 to $32.52 per barrel for the same period
in 2004. Gas revenues increased from $1,473,274 in the first six months of 2003 to $4,416,699 in the same period of 2004 due to an increase in gas production from 260,761 Mcf in the first six months
of 2003 to 761,149 Mcf in the same period of 2004. The increase in gas volume primarily resulted from the addition of the F-3 well in early January 2004. In addition, the average
natural gas sales price increased from $5.65 per Mcf in the first six months of 2003 to $5.79 per Mcf for the same period in 2004. Capital expenditures increased from $3,192,274 in the first six
months of 2003 to $7,850,213 in the same period of 2004, primarily due to $6.3 million of capital expenditures made to compete the F-3 drilling project. Operating expenses increased
from $763,143 in the first six months of 2003 to $1,707,003 for the same period in 2004.

Eugene
Island 339 net crude oil revenues decreased from $8,031,147 in the first six months of 2003 to $340,079 for the same period in 2004, due to a decrease in volumes from 279,307 in
the first six months of 2003 to (26,379) barrels in the first six months of 2004, which gives effect to a negative retroactive adjustment of 236,650 barrels relating to the period of January through
October 2003 for improper credits of production and revenues discussed above. The decrease in production was partially offset by the increase in average crude oil price from $28.75 per barrel
in the first six months of 2003 to $29.75 per barrel for the same period in 2004. Gas revenues decreased from $2,142,170 in the first six months 2003 to $1,183,688 for the same period in 2004,
primarily due to a decrease in natural gas volumes from 377,503 Mcf in the first six months of 2003 to 181,711 Mcf for the same period in 2004, which gives effect to a negative retroactive adjustment
of 90,976 Mcf for improper credits of production and revenues discussed above. Capital expenditures increased from $101,461 in the first six months of 2003 to $6,651,508 in the same period in 2004,
due to various capital projects that were completed in the first six months of 2004, including the C-20 and C-21 drilling projects that
cost approximately $1.5 and $3.3 million, respectively, and upgrades to the C platform facilities that cost approximately $517,000. Operating expenses increased from $220,679 in the first six
months of 2003 to $945,363 in the same period in 2004.

West
Cameron 643 gas revenues decreased from $1,990,535 in the first six months of 2003 to $478,488 for the period in 2004. This is due to a decrease in gas volumes from 343,555 Mcf in
the first six months of 2003 to 90,803 Mcf for the same period in 2004. The decrease in volumes was primarily due to diminishing returns from wells. Operating expenses decreased from $350,054 for the
first six months of 2003 to $154,144 for the same period in 2004, and capital expenditures decreased from $131,819 for the first six months of 2003 to $2,581 for the same period in 2004 due to
production decreases.

East
Cameron 371/381 crude oil revenues decreased from $51,317 in the first six months of 2003 to $18,054 for the same period in 2004, primarily due to the decrease in crude oil
production from 1,588 barrels in the first six months of 2003 to 528 barrels for the same period in 2004. The decrease was partially

15

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offset
by an increase in the average crude oil price from $32.32 per barrel for the first six months of 2003 to $34.52 per barrel for the same period in 2004. Gas revenues decreased from $107,213 for
the first six months of 2003 to $49,477 for the same period in 2004. This is due to a decrease in gas volumes from 19,580 Mcf in the first six months of 2003 to 9,569 Mcf for the same period in 2004.
In addition, the average price received for natural gas decreased from $5.48 per Mcf in the first six months of 2003 to $5.15 per Mcf for the same period in 2004. Capital expenditures were $5,086 in
the first six months of 2003 and were $1,323 for the same period in 2004. Operating expenses were 17,419 in the first six months of 2003 and were $17,071 for the same period in 2004.

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, 2003
future net revenues attributable to the Trust's royalty interests were estimated at $24.8 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, including the discovery of new proved reserves as a result of exploratory drilling, 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 2003 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
profits interest. 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 profits interest 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 estimated
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

16

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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 estimated future Special Costs. In the first six months of 2004, there was a net release of funds from the Special Cost
Escrow account. The Trust's share of the funds released was approximately $1,189,581. The release was primarily due to a decrease of $3,755,526 in projected special costs for capital expenditures. In
the first six 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 $2,515,542. As of June 30, 2004, $7,426,105
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 Royalty Income

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 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
June 30,(1) |            
|----------------------------------------------------------- |  | ------------------------------------------------- | -----------
|
|Crude oil and condensate (bbls)                             |  |                                                   | 263,463    
|Natural gas and gas products (Mcf)                          |  |                                                   | 1,030,158  
|Crude oil and condensate average price, per bbl             |  | $                                                 | 34.11      
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                 | 5.77       
|Crude oil and condensate revenues                           |  | $                                                 | 8,987,940  
|Natural gas and gas products revenues                       |  |                                                   | 5,570,798  
|Production expenses                                         |  |                                                   | (1,707,784 
|Capital expenditures                                        |  |                                                   | (648,079   
|Undistributed net income                                    |  |                                                   | (13,231,454
|Refund of escrowed special costs                            |  |                                                   | 1,344,040  
|                                                            |  |                                                   |            
|Net Proceeds                                                |  | $                                                 | 335,461    
|Royalty interest                                            |  |                                                   | x25        
|                                                            |  |                                                   |            
|Partnership share                                           |  | $                                                 | 83,865     
|Trust interest                                              |  |                                                   | x99.99     
|                                                            |  |                                                   |            
|Trust share                                                 |  | $                                                 | 83,557     
|                                                            |  |                                                   |            

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17

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|                                                                |  | Royalty Properties
Six Months Ended
June 30,(4) |            
|--------------------------------------------------------------- |  | ----------------------------------------------- | -----------
|
|Crude oil and condensate (bbls)(1)                              |  |                                                 | 170,383    
|Natural gas and gas products (Mcf)(2)                           |  |                                                 | 1,262,751  
|Crude oil and condensate average price, per bbl(1)              |  | $                                               | 28.50      
|Natural gas average price, per Mcf (excluding gas products) (2) |  | $                                               | 5.96       
|Crude oil and condensate revenues(1)                            |  | $                                               | 6,857,710  
|Natural gas and gas products revenues(2)                        |  |                                                 | 7,013,950  
|Production expenses(3)                                          |  |                                                 | (3,792,477 
|Capital expenditures(3)                                         |  |                                                 | (14,527,278
|Undistributed net income(5)                                     |  |                                                 | (1,356,586 
|Refund of escrowed special costs                                |  |                                                 | 6,140,140  
|                                                                |  |                                                 |            
|Net Proceeds                                                    |  | $                                               | 335,459    
|Royalty interest                                                |  |                                                 | x25        
|                                                                |  |                                                 |            
|Partnership share                                               |  |                                                 | 83,865     
|Trust interest                                                  |  |                                                 | x99.99     
|                                                                |  |                                                 |            
|Trust share                                                     |  | $                                               | 83,547     
|                                                                |  |                                                 |            

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18

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Item 3. Quantitative and Qualitative Disclosure About Market Risk

No material changes have occurred since our Annual Report on Form 10-K for the year-ended December 31, 2003. Reference is
also made to Note 2 of the Notes to Financial Statements included in Item 1 of this Form 10-Q.

Item 4. Controls and Procedures.

Evaluation of disclosure controls and procedures.Mike Ulrich, as Trust Officer of the Corporate Trustee, has concluded that
the disclosure controls and procedures of the Trust 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:



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

Information
regarding operations provided by the Working Interest Owners, including ChevronTexaco, has been subject to errors and adjustments, some of which have been significant. These
include errors and adjustments that are reflected in this report and other historical reports. Accordingly, while the Trustees make diligent inquiries and request changes to internal controls of the
Working Interest Owners when errors are identified, the Trustees cannot assure Unit holders that other errors or adjustments by Working Interest Owners, whether historical or future, will not affect
future Royalty income and distributions by the Trust.

Changes in Internal Control Over Financial Reporting.During the three months ended June 30, 2004, there has been no
change in the Corporate Trustee's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Corporate Trustee's internal control over
financial reporting relating to the Trust. The Corporate 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.

20

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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.)

|       |  |   |  |                                                                                                                                                                                                                                                                                                                              |  | 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 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 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

No reports on Form 8-K were filed with the Securities and Exchange Commission during the quarter ending June 30, 2004.

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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:
August 13, 2004

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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