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

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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 March 31, 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

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

Texas(State of Incorporation,
or Organization)

76-6004064I.R.S. Employer
Identification No.)JPMorgan Chase Bank
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 May 14, 2003  4,751,510 Units of Beneficial Interest in TEL Offshore Trust.

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NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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PART IFINANCIAL INFORMATION

Item 1. Financial Statements.

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

|                                                                                                                                        |  | March 31,
2003 |           | December 31,
2002
|--------------------------------------------------------------------------------------------------------------------------------------- |  | -------------- | --------- | -----------------
|Assets                                                                                                                                  |  |                |           |                  
|Cash and cash equivalents                                                                                                               |  | $              | 1,459,144 |                  
|Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,077,100 and $28,075,215, respectively |  |                | 190,555   |                  
|                                                                                                                                        |  |                |           |                  
|Total assets                                                                                                                            |  | $              | 1,649,699 |                  
|                                                                                                                                        |  |                |           |                  
|Liabilities and Trust Corpus                                                                                                            |  |                |           |                  
|Distribution payable to Unit holders.                                                                                                   |  | $              | 94,733    |                  
|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)                                                        |  |                | 190,555   |                  
|                                                                                                                                        |  |                |           |                  
|Total liabilities and Trust corpus                                                                                                      |  | $              | 1,649,699 |                  
|                                                                                                                                        |  |                |           |                  

STATEMENTS OF DISTRIBUTABLE INCOME  (Unaudited)

|                                              |  | Three Months Ended
March 31, |         
|--------------------------------------------- |  | ---------------------------- | --------
|
|Royalty income                                |  | $                            | 218,084 
|Interest income                               |  |                              | 2,181   
|                                              |  |                              |         
|                                              |  |                              | 220,265 
|Decrease in reserve for future Trust expenses |  |                              | 28,194  
|General and administrative expenses           |  |                              | (153,726
|                                              |  |                              |         
|Distributable income                          |  | $                            | 94,733  
|Distributions per Unit (4,751,510 Units)      |  | $                            | .019937 

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

1

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STATEMENTS OF CHANGES IN TRUST CORPUS  (Unaudited)

|                                                |  | Three Months Ended
March 31, |        
|----------------------------------------------- |  | ---------------------------- | -------
|
|Trust corpus, beginning of period               |  | $                            | 192,440
|Distributable income                            |  |                              | 94,733 
|Distribution payable to Unit holders            |  |                              | (94,733
|Amortization of net overriding royalty interest |  |                              | (1,885 
|                                                |  |                              |        
|Trust corpus, end of period                     |  | $                            | 190,555
|                                                |  |                              |        

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

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1  Trust Organization

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

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

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

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

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

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

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

Effective
January 1, 2000 PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon Energy Production Company L.P. ("Devon"). As a result of 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 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
Proceeds will be calculated for the collective Royalty Properties owned by Chevron after this date.

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

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

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

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, 2002.



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

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

The
Trust reviews net overriding royalty interest in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not be
recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset and
its eventual disposition. If these

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cash
flows are less than the carrying amount of the asset, an impairment loss is recognized to write down the asset to its estimated fair value. Preparation of estimated expected future cash flows is
inherently subjective and is based on 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. 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, results of operations or cash flows.

Note 3  Net Overriding Royalty Interest

The Royalty entitles the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance, dated January 1,
1983, provides that the Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the Net
Proceeds from their oil and gas properties for the period. Generally, Net Proceeds are the amounts received by the Working Interest Owners from the sale of minerals from the Royalty Properties less
operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and a special cost
reserve. The Special Cost Reserve Account is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and
for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not include amounts received by the Working Interest Owners as advance gas payments,
"take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future delivery of gas.

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Note 4  Distributions to Unit Holders

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

Note 5  Special Cost Escrow Account

The
special cost escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for the reserve of funds for
estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling
projects and other capital expenditures on the 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 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 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 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
$421,000. 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 quarter 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 $414,000. 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 March 31, 2003, approximately $5,226,307 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

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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 for 2002 was $1,392,605. During the first quarter of 2002, the Trust used $55,053 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. The reserve amount for 2003 was calculated to be
$1,364,411.

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 has been entirely recovered from the Trust by the Working Interest Owner as of the first 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 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 reviewing 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

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counterclaim.
The Corporate Trustee cannot predict the likelihood that this claim will actually suceed or the actual extent of this purported accounting error by Texaco.

A
preliminary mediation regarding these matters was held in April 2003 but did not result in a settlement. Discovery is ongoing, and the claims are set for trial in fall of 2003.
The Trust cannot predict the amount if any, or the timing if ever, for any recovery relating tho these claims. However, such claims may be significant if recovered and would be payable only to holders
of the Trust's Units at the time of distribution.

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 March 31, 2003 and 2002

Distributions to Unit Holders for the three months ended March 31, 2003 amounted to $94,733 or $.019937 per Unit. There were no distributions for the three
months ended March 31, 2002.

Gas
revenues increased $998,637, or 183%, to $1,544,042 in the first quarter of 2003 from $545,405 in the first quarter of 2002, primarily due to a 109% increase in the average price
received for natural gas to $4.71 per Mcf in the first quarter of 2003 from $2.25 per Mcf in the first quarter of 2002. Additionally, gas volumes increased by 135% to 327,767 Mcf in the first quarter
of 2003 from 242,603 Mcf in the first quarter of 2002.

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Crude
oil and condensate revenues increased $4,991,702, or 180%, to $7,759,087 in the first quarter of 2003 as compared to $2,767,385 in the same period in 2002, primarily due to a 47%
increase in the average price of crude oil and condensate from $18.65 per barrel in the first quarter of 2002 to $27.49 per barrel in the same quarter of 2003. Additionally, crude oil and condensate
volume increased 90% to 282,262 barrels in the first quarter of 2003 from 148,409 barrels in the first quarter of 2002.

The
Trust's share of capital expenditures increased approximately $1,426,855, from $4,040,258 in the first quarter of 2002 to $5,467,113 in the first quarter of 2003. The increase in
capital expenditures for the first quarter of 2003 related primarily to drilling of 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, compared to capital expenditures for the same period in 2002 which were related to an upgrade of a pipeline pump panel and digital pressure controls for the
I-1 development well on the Ship Shoal 182/183 property.

For
the first quarter of 2003, the Trust had undistributed net income of $35,227. 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 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).

In
the first 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 $421,000, compared to a
net release of funds into the Special Cost Escrow Account of approximately $414,000 net to the Trust in the first 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.

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 2002 was $1,392,605. The reserve amount for 2003 was calculated to be $1,364,411.

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.

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Operational Review

Three Months Ended March 31, 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 $2,104,381 in the first quarter of 2002 to $3,507,739 in the first quarter of 2003, primarily due to an increase in the average crude
oil price from $18.70 per barrel in the first quarter of 2002 to $27.44 per barrel for the same period in 2003. In addition, there was an increase in crude oil production from 112,516 barrels in the
first quarter of 2002 to 127,814 in the first quarter of 2003. The increase in crude oil production was due primarily to the I-2 and I-3 wells and to the new I-4 well completed in early
January 2003. Gas revenues increased from $271,324 in the first quarter of 2002 to $284,590 in the first quarter of 2003 primarily due to an increase in the average natural gas sales price from
$2.56 per Mcf in the first quarter of 2002
to $4.47 per Mcf for the same period in 2003. The increase in the average natural gas price was partially offset by a decrease in gas production from 105,917 Mcf in the first quarter of 2002 to 63,620
Mcf in the first quarter of 2003. The decrease in gas volumes resulted primarily from reduced production on the B-13 and B-10 wells along with decreasing field production. 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 increased from
$3,312,942 in the first quarter of 2002 to $5,352,519 in the first quarter of 2003 primarily due to a large capital outlay ($5.2 million) for drilling of the new I-4 well. For the
first quarter of 2002, the capital expenditures related to an upgrade of pipeline pump panel and digital pressure controls for the I-1 development well. Operating expenses increased
slightly from $378,797 in the first quarter of 2002 to $384,697 for the same period in 2003.

Eugene
Island 339 crude oil revenues increased from $517,255 in the first quarter of 2002 to $4,124,587 for the same period in 2003 due to an increase in volumes from 28,567 in the first
quarter of 2002 to 150,000 barrels in the first quarter of 2003 due primarily to normalization after wells watered out affecting the first quarter of 2002, together with improved performance in 2003
after a workover of the B-1 well along with new B-7 and B-9 wells. In addition, the average crude oil price increased from $18.11 per barrel in the first quarter of 2002 to $27.50 per barrel in the
first quarter of 2003. Gas revenues increased from ($31,065) in the first quarter 2002 to $303,275 in the first quarter of 2003 primarily due to a increase in natural gas volumes from 10,241 Mcf in
the first quarter of 2002 to 52,500 Mcf in the first quarter of 2003 coupled with a ($81,640) estimate adjustment in 2002. 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 from $316,587 in the first quarter of 2002 to $34,665 in the first quarter of 2003 due to a B-7
sidetrack workover and inspection program in the first quarter of 2002. Operating expenses decreased from $186,087 in the first quarter of 2002 to $112,852 in the first quarter of 2003 due to merger
synergies.

West
Cameron 643 gas revenues increased from $44,611 in the first quarter of 2002 to $720,633 in the first quarter of 2003. This is due to the decrease in the average price received for
natural gas from $2.38 per Mcf in the first quarter of 2002 to $4.50 per Mcf in the first quarter of 2003, and a significant increase in gas volumes from 18,726 Mcf in the first quarter of 2002 to
160,212 Mcf for the same period in 2003. The increase in volumes was primarily due to tubing workovers and stimulation work. The gas from West Cameron 643 is currently committed to Texaco Natural
Gas Inc. ("TNGI"). TNGI is a wholly owned

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affiliate
of Texaco Exploration and Production Inc. ("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 are 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 $237,678 in the first
quarter of 2002 to $229,696 for the same period in 2003, and capital expenditures decreased from $377,397 in the first quarter of 2002 to $70,329 for the same period in 2003 due to capital expenditure
normalization.

East
Cameron 371/381 crude oil revenues increased from $16,518 in the first quarter of 2002 to $28,253 in the first quarter of 2003 primarily due to a increase in the average crude oil
price from $19.15 per barrel in the first quarter of 2002 to $30.71 per barrel in the first quarter of 2003. Also, crude oil production increased from 862 barrels in the first quarter of 2002 to 920
barrels for the same period in 2003. Gas revenues decreased from $57,043 in the first quarter of 2002 to $49,061 in the first quarter of 2003. This is due to a decrease in gas volumes from 19,142 Mcf
in the first quarter of 2002 to 11,118 Mcf for the same period in 2003. The decrease in volumes was partially offset by a increase in the average price received for natural gas from $2.98 per Mcf in
the first quarter of 2002 to $4.41 per Mcf in the first quarter of 2003. Capital expenditures were $0 in the first quarter of 2002 and were $4,509 in the first quarter of 2003. Operating expenses
decreased from $54,909 in the first quarter of 2002 to $22,632 in the first quarter 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 $21.2 million. Such reserve study also indicates that approximately 75% of the future net revenues from the
Royalty Properties are expected to be received by the Trust during the next three years. In addition, because the Trust will terminate in the event estimated future net revenues fall below
$2 million, it would be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination
of the Trust, the Trustees will sell for cash all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been
satisfied. The estimates of future net revenues discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties present in
estimating future net revenues for the Royalty Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and
costs assumed by DeGolyer and MacNaughton. In addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The
discussion set forth above is qualified in its entirety by reference to the Trust's 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

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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 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 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 $421,000. 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 quarter 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 $414,000. 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 March 31, 2003, approximately $5,226,307 remained in the Special Cost Escrow Account.

Chevron,
in its capacity as Managing General Partner, has advised the Trust that additional deposits to the Special Cost Escrow Account may be required in future periods in connection
with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits, if made, could result in a significant
reduction in Royalty income in the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.

Overview of Production, Prices and Net Proceeds

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

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

|                                                            |  | Royalty Properties
Three Months Ended
March 31,(1) |           
|----------------------------------------------------------- |  | -------------------------------------------------- | ----------
|
|Crude oil and condensate (bbls)                             |  |                                                    | 282,262   
|Natural gas and gas products (Mcf)                          |  |                                                    | 334,462   
|Crude oil and condensate average price, per bbl             |  | $                                                  | 27.49     
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                  | 4.71      
|Crude oil and condensate revenues                           |  | $                                                  | 7,759,087 
|Natural gas and gas products revenues                       |  |                                                    | 1,564,139 
|Production expenses                                         |  |                                                    | (1,262,649
|Capital expenditures                                        |  |                                                    | (5,467,113
|Undistributed net loss (income)(2)                          |  |                                                    | (35,227   
|(Provision for) Refund of escrowed special costs            |  |                                                    | (1,685,813
|                                                            |  |                                                    |           
|Net Proceeds                                                |  | $                                                  | 872,424   
|Royalty interest                                            |  |                                                    | x25       
|                                                            |  |                                                    |           
|Partnership share                                           |  | $                                                  | 218,106   
|Trust interest                                              |  |                                                    | x99.99    
|                                                            |  |                                                    |           
|Trust share                                                 |  | $                                                  | 218,084   
|                                                            |  |                                                    |           

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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, 2002. Reference is
also made to Note 2 of the Notes to Financial Statements included in Item 1 of this Form 10-Q.

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PART IIOTHER INFORMATION

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

(*) 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 da 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 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)         
|99.1   |  |  |  | Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                            |  |                                 |  |               

(b) Reports on Form 8-K

A
report on Form 8-K was filed with the Securities and Exchange Commission on April 24, 2003.

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SIGNATURES

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

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

Date:
May 14, 2003

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

CERTIFICATION

I,
Mike Ulrich, certify that:

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

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

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

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



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



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

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

|Date: May 14, 2003 | /s/MIKE ULRICHMike Ulrich,Vice President
JPMorgan Chase Bank
|------------------ | ------------------------------------------------------------

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