---

---

---

---

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

---

FORM 10-Q

|/X/ |  | Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended June 30, 2003
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------

or

|/ / |  | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from
 to
|--- |  | ---------------------------------------------------------------------------------------------------------------------------

Commission File Number: 0-6910

---

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

Texas(State of Incorporation,
or Organization)

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

78701(Zip Code)


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

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

Indicate
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 14, 20034,751,510 Units of Beneficial Interest in TEL Offshore Trust.

---



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 principle 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

---



PART IFINANCIAL INFORMATION

Item 1. Financial Statements.

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

|                                                                                                                                        |  | June 30,
2003 |           | December 31,
2002
|--------------------------------------------------------------------------------------------------------------------------------------- |  | ------------- | --------- | -----------------
|Assets                                                                                                                                  |  |               |           |                  
|Cash and cash equivalents                                                                                                               |  | $             | 2,941,865 |                  
|Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,060,535 and $28,047,080, respectively |  |               | 178,985   |                  
|                                                                                                                                        |  |               |           |                  
|Total assets                                                                                                                            |  | $             | 3,120,850 |                  
|                                                                                                                                        |  |               |           |                  
|Liabilities and Trust Corpus                                                                                                            |  |               |           |                  
|Distribution payable to Unit holders.                                                                                                   |  | $             | 1,577,454 |                  
|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)                                                        |  |               | 178,985   |                  
|                                                                                                                                        |  |               |           |                  
|Total liabilities and Trust corpus                                                                                                      |  | $             | 3,120,850 |                  
|                                                                                                                                        |  |               |           |                  

STATEMENTS OF DISTRIBUTABLE INCOME  (Unaudited)

|                                                         |  | Three Months Ended
June 30, |           | Six Months Ended
June 30, |  
|-------------------------------------------------------- |  | --------------------------- | --------- | ------------------------- | -
|
|Royalty income                                           |  | $                           | 1,819,013 |                           | $
|Interest income                                          |  |                             | 1,882     |                           |  
|                                                         |  |                             |           |                           |  
|                                                         |  |                             | 1,820,895 |                           |  
|Decrease (Increase) in reserve for future Trust expenses |  |                             | (0        | )                         |  
|General and administrative expenses                      |  |                             | (243,441  | )                         |  
|                                                         |  |                             |           |                           |  
|Distributable income                                     |  | $                           | 1,577,454 |                           | $
|                                                         |  |                             |           |                           |  
|Distributions per Unit (4,751,510 Units)                 |  | $                           | .331990   |                           | $
|                                                         |  |                             |           |                           |  

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

1

---

STATEMENTS OF CHANGES IN TRUST CORPUS  (Unaudited)

|                                                |  | Three Months Ended
June 30, |            | Six Months Ended
June 30, |  
|----------------------------------------------- |  | --------------------------- | ---------- | ------------------------- | -
|
|Trust corpus, beginning of period               |  | $                           | 190,555    |                           | $
|Distributable income                            |  |                             | 1,577,454  |                           |  
|Distribution payable to Unit holders            |  |                             | (1,577,454 | ))                        |  
|Amortization of net overriding royalty interest |  |                             | (11,570    | )                         |  
|                                                |  |                             |            |                           |  
|Trust corpus, end of period                     |  | $                           | 178,985    |                           | $
|                                                |  |                             |            |                           |  

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

2

---

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.

3

---

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 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 such 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 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

4

---

Cameron
371/381 from December 1, 1994 until May 1, 2002, and with respect to the same properties including West Cameron 643 and East Cameron 371/381 thereafter; PennzEnergy/Devon with
respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until October 1, 1995, and with respect to Eugene Island 348 and
Eugene Island 208 thereafter; Texaco with respect to West Cameron 643 and East Cameron 371/381 for periods beginning on 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 mergers
to the original name of the Corporate Trustee, Texas Commerce Bank National Association) ("Corporate Trustee") in accordance with the instructions to Form 10-Q and does not include
all of the information required by accounting principles generally accepted in the United States of America for complete financial statements, although the Corporate Trustee and the individual
trustees (collectively, the "Trustees") believe that the disclosures are adequate to make the information presented not misleading. The information furnished reflects all adjustments, which are, in
the opinion of the Trustees, necessary for a fair presentation of the results for the interim periods presented. The financial information should be read in conjunction with the financial statements
and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2001.

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



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

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

5

---

The
Trust reviews net overriding royalty interest in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not be
recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset and
its eventual disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss is recognized to write down the asset to its estimated fair value. Preparation of
estimated expected future cash flows is inherently subjective and is based on management's best estimate of assumptions concerning expected future conditions. There were no write-downs taken in the
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

6

---

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. 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 fo 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 six months of 2003, there was a net deposit of funds to the Special Cost Escrow Account. The Trust's share of the funds deposited was approximately
$2,515,088. The deposit was primarily a result of an increase in the Working Interest Owners' current estimate of projected capital expenditures on the Royalty Properties. In the first six 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 approximately $596,836. The release was made primarily due to a

7

---

decrease
in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties. As of June 30, 2003, approximately $7,308,088 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 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 June 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 that they are in general compliance with applicable health, safety and environmental laws and regulations
that have taken effect at the federal, state and local levels, costs may be incurred to comply with current and proposed environmental legislation which could result in increased operating expenses on
the Royalty Properties.

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

In
connection with the foregoing litigation, TEPI has also asserted a counterclaim for overpayment of $880,632 prior to and during the third quarter of 1999. TEPI has claimed that these
costs should have been allocated to the Trust. This counterclaim has been asserted notwithstanding Texaco's own internal audit

8

---

and
revisions relating to the same periods in 1998 and described in the Trust's Form 10-K for the year ended December 31, 1999 and 1998. The Trustees are currently reveiwing
the facts relating to this alleged overpayment due to Texaco accounting errors. Chevron has notified the Corporate Trustee that it currently does not intend to withhold revenues from production of
East Cameron 371/381 in connection with this counterclaim. The Corporate Trustee cannot predict the liklihood that this claim will actually succeed or the actual extent of this purported accounting
error by Texaco.

A
preliminary meditation regarding these matters was held in April 2003 but has not resulted in a settlement as of the date of this report. Discovery is ongoing, and the claims
are set for trial in fall 2003. The Trust cannot predict the amount if any, or the timing if ever, for any recovery relating to these claims. However, such claims would be payable only to holders of
the Trust's Units at the time of distribution.

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 June 30, 2003 and 2002

Distributions to Unit holders for the three months ended June 30, 2003 amounted to $1,577,454 or $.331990 per Unit as compared to $364,941 or $.076805 per
Unit for the same period in 2002. The increase in distributable income for the second quarter of 2003 was primarily due to increases in both oil and gas prices and production volumes, as described
below.

9

---

Crude
oil and condensate revenues increased $6,621,164, or 195%, to $10,016,865 in the second quarter of 2003 as compared to $3,395,701 in the same period in 2002, due in part to a 51%
increase in the average price of crude oil and condensate from $21.64 per barrel in the second quarter of 2002 to $32.58 per barrel in the same period in 2003. Additionally, crude oil and condensate
volumes increased
96% from 156,903 barrels in the second quarter of 2002 to 303,463 barrels in the second quarter of 2003.

Gas
revenues increased $4,099,314, or 857%, to $4,577,570 in the second quarter of 2003 from $478,256 in the second quarter of 2002, primarily due to a 154% increase in the average price
received for natural gas to $6.13 per Mcf in the second quarter of 2003 from $2.41 per Mcf in the second quarter of 2002. Additionally, gas volumes increased by 549,265 Mcf to 747,306 Mcf in the
second quarter of 2003 from 198,041 Mcf in the second quarter of 2002. The higher gas volumes were primarily due to a retroactive price adjustment as a result of previously understated production and
production from the I-4 well which came online in January of 2003.

The
Trust's share of capital expenditures decreased approximately $2,596,672 or 446% from $582,635 in the second quarter 2002 to ($2,014,037) in the second quarter of 2003. The lower
capital expenditures in the second quarter of 2003 were due primarily to a capital expenditure adjustment and reallocation of drilling costs associated with the drilling of the I-4 well.

For
the second quarter of 2003, the Trust's share of undistributed net income was $8,241. 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). The undistributed net income for the second quarter of 2003 was primarily related to the loss carryforward referred to above on the Eugene Island 348 property.

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 was approximately $2,094,143, compared to a
net release of funds from the Special Cost Escrow Account of $182,172 net to the Trust in the second 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.

Six Months Ended June 30, 2003 and 2002

Distributions to Unit holders for the six months ended June 30, 2003 amounted to $1,672,187 or $.351927 per Unit as compared to $364,941 or $.076805 per
Unit for the same period in 2002. The increase in distributable income for the first six months 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 $11,612,865, or 188%, to $17,755,951 in the first six months of 2003 as compared to $6,163,086 in the same period in 2002, primarily due to a
93% increase in crude oil and condensate volumes from the first six months of 2002 to the same period in 2003. Crude oil volumes increased from 305,312 barrels in second quarter 2002 to 589,725
barrels in second quarter 2003. The increase in crude oil and condensate volumes along with the 49% increase in the average price of crude oil and condensate from $20.19 per barrel in the six months
ended June 30, 2002 to $30.14 per barrel in the same period in 2003 account for the increase in revenues.

10

---

Gas
revenues increased $5,097,951 or 498%, to $6,121,612 in the six months ended June 30, 2003 from $1,023,661 in the same period in 2002, primarily due to a 145% increase in the
average price received for natural gas to $5.69 per Mcf in the six months ended June 30, 2003 from $2.32 per Mcf in the six months ended June 30, 2002. This increase in average price
together with a 144% increase in gas volumes to 1,075,073 per Mcf in the first six months of 2003 from 440,694 per Mcf for the same period in 2002 account for the increase in gas revenues.

The
Trust's share of capital expenditures decreased approximately $1,169,888, or 25% from $4,622,893 in the six months ended June 30, 2002 to $3,453,005 in the same period in
2003. This decrease was primarily due to an upgrade of a pipeline pump panel and digital pressure controls during 2002 on the Ship Shoal 182/183 property.

For
the first six months of 2003, the Trust's share of undistributed net income was $43,468. The undistributed net income for the second quarter of 2003 was primarily related to the loss
carryforward referred to above on the Eugene Island 348 property.

In
the first six months of 2003, there was a deposit of funds into the Special Cost Escrow Account. The Trust's share of the funds deposited was approximately $2,515,542 compared to a
net release of funds from the Special Cost Escrow Account of approximately $583,140 net release to the Trust in the first six months of 2002. The Special Cost Escrow is set aside for estimated
expeditures as provided for in the Conveyence. 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 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 the first quarter of 1998, the Trust determined that
the Trust's cash reserve was sufficient at that time to provide for future administrative expenses in connection with the winding up of the Trust. The Trust determined that a cash reserve equal to
three times the average expenses of the Trust during each of the past three years was sufficient at this time to provide for future administrative expenses in connection with the winding up of the
Trust. The reserve amount for 2003 is $1,364,411. The reserve amount at December 31, 2002 was $1,392,605.

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.

11

---

Operational Review

Three Months Ended June 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 $2,191,313 in the second quarter of 2002 to $5,773,579 in the second quarter of 2003, primarily due to increases in both production
and prices. Crude oil production increased from 96,948 barrels in the second quarter of 2002 to 168,424 barrels in the second quarter of 2003. The increase in crude oil production was due primarily to
producton from the I-4 well which came online in January of 2003. Furthermore, there was a significant increase in the average price of crude oil from $22.60 per barrel in the second quarter of 2002
to $34.28 per barrel for the same period in 2003. Gas revenues increased from $106,600 in the second quarter of 2002 to $1,188,684 in the second quarter of 2003 primarily due to an increase in both
production and prices. Gas volumes increased from 46,960 Mcf in the second quarter of 2002 to 197,141 Mcf in the second quarter of 2003. The average gas sales price also increased significantly from
$2.27 per Mcf in the second quarter of 2002 to $6.03 per Mcf in the second quarter of 2003. The increase in gas volumes was primarily due to a full four months of production from
the I-4 well that came online in January of 2003. The gas from Ship Shoal 182/183 is committed to Dynegy Inc. ("Dynegy") at a calculated price based on the monthly
Inside FERC Tennessee-Louisiana Zone 1 Index. Capital expenditures decreased from $330,463 in the second quarter of 2002 to ($2,160,245) in the second quarter of 2003 primarily due to a reallocation
of drilling costs from the I-4 well to a non-trust lease. Operating expenses decreased slightly from $381,997 in the second quarter of 2002 to $378,446 for the same period in 2003.

Eugene
Island 339 crude oil revenues increased from $1,064,366 in the second quarter of 2002 to $3,906,560 in the second quarter of 2003, primarily due to significant increases in both
prices and production. The average price of crude oil increased from $19.95 per barrel in the second quarter of 2002 to $30.21 per barrel in the second quarter of 2003. Crude oil production increased
from 53,355 barrels in the second quarter of 2002 to 129,307 barrels in the second quarter of 2003 primarily due to increased production on the B-7 well, partially offset by field
declines. Gas revenues increased from $99,308 in the second quarter of 2002 to $1,838,895 in the second quarter of 2003, primarily due to a production increase from 35,270 Mcf in second quarter 2002
to 325,003 Mcf in second quarter 2003. The average natural gas sales price increased from $2.82 per Mcf in the second quarter of 2002 to $5.66 in the second quarter of 2003. The gas from this property
is currently committed to Dynegy at a calculated price based on the monthly Inside FERC Tennessee-Louisiana Zone 1 Index. Capital expenditures decreased to $66,796 in the second quarter of 2003 from
$186,688 in the second quarter of 2002 due to stabilization after completion of both the B-7 sidetrack workover and the inspection program. Operating expenses increased from $37,477 in the second
quarter of 2002 to $107,827 in the second quarter of 2003 due to understated expenses in the second quarter 2002.

West
Cameron 643 gas revenues increased from $57,046 in the second quarter of 2002 to $1,269,902 in the second quarter of 2003, primarily due to an increase in gas volumes from 22,753
Mcf in the second quarter of 2002 to 183,343 Mcf in the second quarter of 2003 and the significant increase in the average price received for natural gas from $2.51 per Mcf in the second quarter of
2002 to $6.93 per Mcf in the second quarter of 2003. The increase in volumes was primarily due to a Columbia Gulf Gas pipeline leak and the B-8 sidetrack being shut in due to water production in 2002.
The gas from West Cameron 643 is

12

---

currently
committed to Texaco Natural Gas Inc. ("TNGI"). TNGI is a wholly owned affiliate of TEPI. TNGI purchases natural gas from TEPI and resells such gas to a variety of third-party
customers at a variety of downstream delivery points. The prices that TNGI pays TEPI for the gas production is based on the actual sale prices that TNGI receives from its third-party customers less
the actual transportation cost, if any, that TNGI pays to a transporting pipeline. TEPI's proceeds are based on 100% of the actual resale price of the gas, less actual transportation. Operating
expenses decreased from $172,778 in the second quarter of 2002 to $120,358 for the same period in 2003, primarily due to charges being reallocated to other properties. Capital expenditures increased
slightly from $52,624 in the second quarter of 2002 to $61,490 in the second quarter of 2003.

East
Cameron 371/381 crude oil revenues decreased from $27,066 in the second quarter of 2002 to $23,064 in the second quarter of 2003 primarily due to a decrease in the volume of crude
oil from 1,149 barrels for the second quarter of 2002 to 668 barrels for the same period in 2003. This production decline was partially offset by an increase in the average price received of $23.56
per barrel in the second quarter of 2002 to $34.53 per barrel in the second quarter of 2003. Gas revenues increased from $42,059 in the second quarter of 2002 to $58,152 in the second quarter of 2003.
This increase was primarily due to an increase in the average price received for natural gas from $2.53 per Mcf in the second quarter of 2002 to $6.87 per Mcf in the second quarter of 2003. This price
increase was partially offset by a decrease in volume from 16,603 Mcf for the second quarter of 2002 to 8,462 for the same period in 2003. Capital expenditures increased from $0 in the second quarter
of 2002 to $577 in the second quarter of 2003. Operating expenses decreased from $47,498 in the second quarter of 2002 to ($5,213) in the second quarter of 2003.

Six Months Ended June 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 $4,295,694 in the first six months of 2002 to $9,281,318 in the first six months of 2003, primarily due to an increase in the average
price of crude oil from $20.51 per barrel in the first six months of 2002 to $31.33 per barrel in the first six months of 2003. Crude oil production increased from 209,464 barrels in the first six
months of 2002 to 296,238 barrels in the first six months of 2003, primarily as a result of production from the I-4 well, which came online in January of 2003. Gas revenues increased from
$377,924 in the first six months of 2002 to $1,473,274 in the first six months of 2003 primarily due to a significant increase in the average natural gas sales price from $2.47 per Mcf in the first
six months of 2002 to $5.65 per Mcf in the first six months of 2003. Gas volumes increased from 152,877 Mcf in the first six months of 2002 to 260,761 Mcf in the first six months of 2003, primarily as
a result of production from the I-4 well, which came online in January of 2003. Capital expenditures decreased from $3,643,405 in the first six months of 2002 to $3,192,274 in the same
period of 2003. Operating expenses increased from $760,794 for the first six months of 2002 to $763,143 for the first six months of 2003.

Eugene
Island 339 crude oil revenues increased from $1,581,621 in the first six months of 2002 to $8,031,147 in the first six months of 2003, primarily due to increases in both prices
and production. Crude oil production increased from 81,922 barrels in the first six months of 2002 to 279,307 barrels in the first six months of 2003 primarily due to increased production on the
B-7 and B-1 wells, partially offset by field

13

---

declines.
The average price of crude oil increased from $19.31 per barrel in the first six months of 2002 to $28.75 per barrel in the first six months of 2003. Gas revenues increased from $68,243 in
the first six months of 2002 to $2,142,170 in the first six months of 2003, primarily due to a significant increase in production from 45,511 Mcf for the first six months of 2002 to 377,503 Mcf for
the same period in 2003. There was also a significant increase in the average natural gas sales price from $1.50 per Mcf in the first six months of 2002 to $5.67 in the first six months of 2003.
Capital expenditures decreased from $503,275 in the first six months of 2002 to $101,461 in the first six months of 2003. Operating expenses decreased slightly from $223,564 in the first six months of
2002 to $220,679 in the first six months 2003.

West
Cameron 643 gas revenues increased from $101,657 in the first six months of 2002 to $1,990,535 in the first six months of 2003, primarily due to an increase in gas volumes from
41,479 Mcf in the first six months of 2002 to 343,555 Mcf for the same period in 2003. The average natural gas sales price from $2.45 per Mcf in the first six months of 2002 to $5.79 per Mcf in the
first six months of 2003. Operating expenses decreased from $410,456 in the first six months of 2002 to $350,054 for the first six
months of 2003. Capital expenditures decreased from $430,021 in the first six months of 2002 to $131,819 in the first six months of 2003.

East
Cameron 371/381 crude oil revenues increased from $43,584 in the first six months of 2002 to $51,317 in the first six months of 2003 due in part to an increase in the average price
of crude oil from $21.67 per barrel in the first six months of 2002 to $32.32 per barrel for the same period in 2003. This crude oil price increase was offset by a production decrease from 2,011
barrels in the first six months of 2002 to 1,588 barrels in the first six months of 2003. Gas revenues increased from $99,102 in the first six months of 2002 to $107,213 in the first six months of
2003, due in part to an increase in the average natural gas sales price from $2.77 per Mcf in the first six months of 2002 to $5.48 Mcf in the first six months of 2003. The price increase was
partially offset by a decrease in gas volumes from 35,745 Mcf in the first six months of 2002 to 19,580 in the first six months of 2003. Capital expenditures increased from $0 in the first six months
of 2002 to $5,086 in the first six months of 2003. Operating expenses decreased from $102,407 in the first six months of 2002 to $17,419 in the first six 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 were estimated at $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 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

14

---

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 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. The deposit was primarily a result of an increase in the Working Interest Owners' current estimate of projected capital expenditures
on the Royalty Properties. In the first six 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 approximately $583,140.
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 June 30, 2003,
approximately $7,513,064 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

15

---

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)                             |  |                                                   | 307,463   
|Natural gas and gas products (Mcf)                          |  |                                                   | 764,120   
|Crude oil and condensate average price, per bbl             |  | $                                                 | 32.58     
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                 | 6.13      
|Crude oil and condensate revenues                           |  | $                                                 | 10,016,865
|Natural gas and gas products revenues                       |  |                                                   | 4,643,486 
|Production expenses                                         |  |                                                   | (1,013,011
|Capital expenditures                                        |  |                                                   | 2,014,037 
|Undistributed Net Income(2)                                 |  |                                                   | (8,241    
|(Provision for) Refund escrowed special costs               |  |                                                   | (8,376,356
|                                                            |  |                                                   |           
|Net Proceeds                                                |  | $                                                 | 7,276,780 
|Royalty interest                                            |  |                                                   | x25       
|                                                            |  |                                                   |           
|Partnership share                                           |  | $                                                 | 1,819,195 
|Trust interest                                              |  |                                                   | x99.99    
|                                                            |  |                                                   |           
|Trust share                                                 |  | $                                                 | 1,819,013 
|                                                            |  |                                                   |           

---

16

---

|                                                            |  | Royalty Properties
Six Months Ended
June 30,(1) |            
|----------------------------------------------------------- |  | ----------------------------------------------- | -----------
|
|Crude oil and condensate (bbls)                             |  |                                                 | 589,725    
|Natural gas and gas products (Mcf)                          |  |                                                 | 1,098,582  
|Crude oil and condensate average price, per bbl             |  | $                                               | 30.14      
|Natural gas average price, per Mcf (excluding gas products) |  | $                                               | 5.69       
|Crude oil and condensate revenues                           |  | $                                               | 17,775,952 
|Natural gas and gas products revenues                       |  |                                                 | 6,207,625  
|Production expenses                                         |  |                                                 | (2,275,660 
|Capital expenditures                                        |  |                                                 | (3,453,076 
|Undistributed Net Income(2)                                 |  |                                                 | (43,468    
|(Provision for) Refund escrowed special costs               |  |                                                 | (10,062,169
|                                                            |  |                                                 |            
|Net Proceeds                                                |  | $                                               | 8,149,204  
|Royalty interest                                            |  |                                                 | x25        
|Partnership share                                           |  | $                                               | 2,037,301  
|Trust interest                                              |  |                                                 | x99.99     
|                                                            |  |                                                 |            
|Trust share                                                 |  | $                                               | 2,037,097  
|                                                            |  |                                                 |            

---

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.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.

17

---

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

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



18

---



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

Changes in Internal Controls.To the knowledge of the Corporate Trustee, there have been no significant changes in the
Corporate Trustee's internal controls or in other factors that could significantly affect the Corporate Trustee's internal controls subsequent to the date the Corporate Trustee completed its
evaluation. The Corporate 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.

19

---



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 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 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 April 24, 2003 and June 27, 2003.

20

---



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 14, 2003

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

21

---

QuickLinks