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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 June 30, 2002
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------

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, Trustee
Institutional Trust Services
700 Lavaca Street
Austin, Texas 78701(Address of Principal
Executive Offices)

78701(Zip Code)


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

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

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

As
of August 12, 2002  4,751,510 Units of Beneficial Interest in TEL Offshore Trust.

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NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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PART IFINANCIAL INFORMATION

Item 1. Financial Statements.

TEL OFFSHORE TRUST  STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

|                                                                                                                                        |  | June 30,
2002 |           | December 31,
2001
|--------------------------------------------------------------------------------------------------------------------------------------- |  | ------------- | --------- | -----------------
|
|Assets                                                                                                                                  |  |               |           |                  
|Cash and cash equivalents                                                                                                               |  | $             | 1,361,934 |                  
|Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,060,535 and $28,047,080, respectively |  |               | 207,120   |                  
|                                                                                                                                        |  |               |           |                  
|Total assets                                                                                                                            |  | $             | 1,569,054 |                  
|                                                                                                                                        |  |               |           |                  
|Liabilities and Trust Corpus                                                                                                            |  |               |           |                  
|Distribution payable to Unit holders.                                                                                                   |  | $             | 364,941   |                  
|Reserve for future Trust expenses                                                                                                       |  |               | 996,993   |                  
|Commitments and contingencies (Note 7)                                                                                                  |  |               |           |                  
|Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)                                                        |  |               | 207,120   |                  
|                                                                                                                                        |  |               |           |                  
|Total liabilities and Trust corpus                                                                                                      |  | $             | 1,569,054 |                  
|                                                                                                                                        |  |               |           |                  

STATEMENTS OF DISTRIBUTABLE INCOME  (Unaudited)

|                                                         |  | Three Months Ended
June 30, |          | Six Months Ended
June 30, |  
|-------------------------------------------------------- |  | --------------------------- | -------- | ------------------------- | -
|
|Royalty income                                           |  | $                           | 822,605  |                           | $
|Interest income                                          |  |                             | 3,022    |                           |  
|                                                         |  |                             |          |                           |  
|                                                         |  |                             | 825,627  |                           |  
|Decrease (Increase) in reserve for future Trust expenses |  |                             | (260,340 | )                         |  
|General and administrative expenses                      |  |                             | (200,346 | )                         |  
|                                                         |  |                             |          |                           |  
|Distributable income                                     |  | $                           | 364,941  |                           | $
|                                                         |  |                             |          |                           |  
|Distributions per Unit (4,751,510 Units)                 |  | $                           | .076805  |                           | $
|                                                         |  |                             |          |                           |  

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
June 30, |          | Six Months Ended
June 30, |  
|----------------------------------------------- |  | --------------------------- | -------- | ------------------------- | -
|
|Trust corpus, beginning of period               |  | $                           | 218,916  |                           | $
|Distributable income                            |  |                             | 364,941  |                           |  
|Distribution payable to Unit holders            |  |                             | (364,941 | )                         |  
|Amortization of net overriding royalty interest |  |                             | (11,796  | )                         |  
|                                                |  |                             |          |                           |  
|Trust corpus, end of period                     |  | $                           | 207,120  |                           | $
|                                                |  |                             |          |                           |  

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 as being owned by Chevron, are each now controlled by a subsidiary of ChevronTexaco.

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

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

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

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2000; 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; and Amerada with respect to East Cameron 354 for
periods beginning on or after January 1, 1998; and Devon with respect to Eugene Island 348 and Eugene Island 208 for periods beginning on or after January 1, 2000).

Note 2  Basis of Accounting

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

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



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

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

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

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

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

The
amount of cash distributions by the Trust is dependent on, among other things, the sales prices for oil and gas produced from the Royalty Properties and the quantities of oil and gas
sold. It should be noted that substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and
other actions taken by major petroleum producing nations, as well as the regional supply and demand for gas, weather, industrial growth, conservation measures, competition and other variables. The
Trust does not enter into any hedging transactions on future production. Accordingly, the Statement of Financial Accounting Standards No. 133, "Accounting of Derivative Instruments and Hedging
Activities," as amended, that was effective January 1, 2001 has not had an impact on the financial statements.

Note 3  Net Overriding Royalty Interest

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

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Note 4  Distributions to Unit Holders

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

Note 5  Special Cost Escrow Account

The Conveyance provides for the reserve of funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of
abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royal Properties. As provided in the Conveyance, the amount of
funds to be reserved is determined based on certain factors, including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current
net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein
referred to as the "Special Cost Escrow Account." The Trust's share of interest generated from the Special Cost Escrow Account serves to reduce the Trust's share of allocated production costs. Special
Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been paid are no longer included
in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow Account will generally be made when the balance in the Special Cost Escrow Account is less than 125% of future Special Costs
and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a
Net Revenues Shortfall, amounts in the Special Cost Escrow Account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow Account generally
will also be released when the balance in such account exceeds 125% of future Special Costs. In the first six months of 2001, there was a net deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was approximately $399,376. 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 decrease in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty
Properties. As of June 30, 2002, approximately $4,852,963 remained in the Special Cost Escrow Account.

Chevron,
in its capacity as Managing General Partner, has advised the Trust that additional deposits to the Special Cost Escrow Account may be required in future periods in connection
with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in
Royalty income in the periods in

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

Note 6  Expense Reserve

The Trust made a determination in 1998 to maintain a cash reserve equal to three times the average expenses of the Trust during each of the past three years to
provide for future administrative expenses in connection with the winding up of the Trust. The reserve amount for 2001 was $978,971. The excess amount in the reserve at January 1, 2001, of
$138,513 was distributed to Unit holders in the first quarter of 2001. The reserve amount at June 30, 2002 was calculated to be $996,993. The amount of $18,022 was withheld from Unit holders in
the second quarter of 2002 to maintain the cash reserve.

Note 7  Commitments and Contingencies

During 1994, the Working Interest Owner on the Eugene Island 348 property settled a gas imbalance on that property for approximately $2,696,000. The Trust's share
of this settlement amount was approximately $674,000, of which approximately $623,539 has been recovered from the Trust by the Working Interest Owner through the second quarter of 2002. The remainder
will be subject to recovery from the Trust during future periods in accordance with the Conveyance. The Working Interest Owner has advised the Trust that future Royalty income attributable to all of
the Royalty Properties owned by the Working Interest Owner will be used to offset the Trust's share of such settlement amounts. Based on current production, prices and expenses for the Royalty
Properties owned by the Working Interest Owner, it is estimated that Royalty income attributable to such properties will be retained by the
Working Interest Owner for the remaining life of the Trust. The Trust does not anticipate that retention of such Royalty income by PennzEnergy will have a material effect on the Trust's Royalty income
as a whole.

The
Working Interest Owners have advised the Trust that, although they believe that they are in general compliance with applicable health, safety and environmental laws and regulations
that have taken effect at the federal, state and local levels, costs may be incurred to comply with current and proposed environmental legislation which could result in increased operating expenses on
the Royalty Properties.

On
September 21, 2001, the Trust gave written demand to, and on October 11, 2001, the Trust filed suit against, the 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 the Working Interest Owner improperly reduced the percentage of Net Proceeds payable to the Trust and improperly deducted from Gross Proceeds certain
costs that the Trust believes are atrributable to the Working Interest Owner's separate operations on an offsetting lease. The Trust cannot predict the amount, if any, or the timing, if ever, for any
recovery relating to these claims. However, production allocated by the East Cameron 371 Working Interest Owner to the Trust thus far has represented in excess of 60% of total

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oil production and in excess of 20% of total natural gas production for the Trust in each of the past three years. Accordingly, such claims may be significant if recovered and would be payable only
to holders of the Trust's Units at the time of distribution.

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

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

Critical Accounting Policies

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



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

Net Overriding Royalty Interest and Distributions

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



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

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

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

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

Financial Review

Three Months Ended June 30, 2002 and 2001

Distributions to Unit holders for the three months ended June 30, 2002 amounted to $364,941 or $.076805 per Unit as compared to $1,318,313 or $.277451 per
Unit for the same period in 2001. The decrease in distributable income for the second quarter of 2002 was primarily due to decreased oil and gas prices and production volume declines, as described
below.

Gas
revenues decreased $2,532,105, or 84%, to $493,866 in the second quarter of 2002 from $3,025,971 in the second quarter of 2001, primarily due to a 62% decrease in the average price
received for natural gas to $2.24 per Mcf in the second quarter of 2002 from $6.21 per Mcf in the second quarter of 2001. Additionally, gas volumes decreased by 55% to 220,205 Mcf in the second
quarter of 2002 from 487,653 Mcf in the second quarter of 2001. The lower gas volumes were primarily due to natural production declines in wells on East Cameron 353 and East Cameron 371/381, as well
as freezing and compressor problems on Ship Shoal 182/183.

Crude
oil and condensate revenues decreased $1,380,064, or 29%, to $3,395,701 in the second quarter of 2002 as compared to $4,775,765 in the same period in 2001, primarily due to a 29%
decrease in the average price of crude oil and condensate from $30.67 per barrel in the second quarter of 2001 to $21.64 per barrel in the same quarter 2002. Crude oil and condensate volumes increased
only 1% from the 2001 first quarter to the 2002 first quarter.

The
Trust's share of capital expenditures decreased approximately $322,882, or 36% from $905,517 in the second quarter 2001 to $582,635 in the second quarter of 2002. The lower capital
expenditures in the second quarter of 2002 were due primarily to normalization of operating expense on Eugene Island 348, East Cameron 371/381, and West Cameron 643.

For
the second quarter of 2002, the Trust's share of undistributed net income of $14,941. 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

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positive Net Proceeds earned by the related Working Interest Owner(s). The undistributed net income for the second quarter of 2002 was primarily related to the loss carryforward referred to above on
the Eugene Island 348 property.

In
the second 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 $182,172, compared to a
net deposit of funds into the Special Cost Escrow Account of $23,749 net to the Trust in the second quarter of 2001. The Special Cost Escrow is set aside for estimated abandonment costs and future
capital expenditures as provided for in the Conveyance. For additional information relating to the Special Cost Escrow see "Special Cost Escrow Account" below.

Six Months Ended June 30, 2002 and 2001

Distributions to Unit holders for the six months ended June 30, 2002 amounted to $364,941 or $.076805 per Unit as compared to $2,915,316 or $.613556 per
Unit for the same period in 2001. The decrease in distributable income for the first six months of 2002 was primarily due to decreased oil and gas prices, and production volume declines, as described
below.

Gas
revenues decreased $6,031,139, or 85%, to $1,104,100 in the six months ended June 30, 2002 from $7,135,239 in the same period in 2001, primarily due to a 64% decrease in the
average price received for natural gas to $2.27 per Mcf in the six months ended June 30, 2002 from $6.53 per Mcf in the six months ended June 30, 2001. The decrease in average price and
the 65% decrease in gas volumes to 485,692 per Mcf in the first six months of 2002 from 1,091,321 per Mcf for the same period in 2001 account for the decline in revenues.

Crude
oil and condensate revenues decreased $3,609,969, or 37%, to $6,163,086 in the first six months of 2002 as compared to $9,773,055 in the same period in 2001, primarily due to a 5%
decrease in the crude oil and condensate volume from the first six months in 2001 to the same period in 2002. The decrease in crude oil and condensate volumes along with the 34% decrease in the
average price of crude oil and condensate from $30.51 per barrel in the six months ended June 30, 2001 to $20.15 per barrel in the same period in 2002 account for the decline in revenues.

The
Trust's share of capital expenditures increased approximately $3,521,237, or 320% from $1,101,656 in the six months ended June 30, 2001 to $4,622,893 in the same period in
2002. This increase was primarily due 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 six months of 2002, the Trust's share had undistributed net income of $28,385. The undistributed net income for the second quarter of 2002 was primarily related to the loss
carryforward referred to above on the Eugene Island 348 property.

In
the first six months of 2002, there was a release of funds into the Special Cost Escrow Account. The Trust's share of the funds released was approximately $596,836 compared to a net
deposit of funds into the Special Cost Escrow Account of approximately $399,376 net to the Trust in the first six months of 2001. Additionally $16,250.08 was deposited to the Special Cost Escrow
Account during the first six months of 2002.

12

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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 2001 was $978,971. The excess amount in the reserve at January 1, 2002, of $138,513 was distributed to Unit holders in the first quarter
of 2001. The reserve amount for 2002 was calculated to be $996,993. The amount of $18,022 was withheld from Unit holders in the second quarter of 2002 to maintain the cash reserve.

Other

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

Operational Review

Three Months Ended June 30, 2002 and 2001

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

Ship
Shoal 182/183 crude oil revenues decreased from $3,071,681 in the second quarter of 2001 to $2,191,313 in the second quarter of 2002, primarily due to a decrease in both production
and prices. Crude oil production decreased from 103,417 barrels in the second quarter of 2001 to 96,948 barrels in the second quarter of 2002. The decrease in crude oil production was due primarily to
volumes being down to fourth quarter 2001 levels. The results from the I-1 development well were disappointing as it incurred LACT unit problems in March after a February upgrade and crude
oil production initially increased in the first quarter of 2002. Furthermore, there was a decrease in the average price of crude oil price from $29.70 per barrel in the second quarter of 2001 to
$22.60 per barrel for the same period in 2002. Gas revenues decreased from $583,048 in the second quarter of 2001 to $106,600 in the second quarter of 2002 primarily due to a decrease in both
production and prices. Gas volumes decreased from 76,538 Mcf in the second quarter of 2001 to 46,960 Mcf in the second quarter of 2002. The average gas sales price also decreased significantly from
$6.91 per Mcf in the second quarter of 2001 to $2.27 per Mcf in the second quarter of 2002. The decrease in gas volumes was primarily due to disappointing results from the I-1 well and the
B15 well being taken off production for two weeks. Furthermore, wells on this property incurred freezing and compressor
problems in February 2002. The gas from Ship Shoal 182/183 is committed to Dynegy Inc. ("Dynegy") at a calculated price based on the monthly Inside FERC Tennessee-Louisiana Zone 1 Index.
In addition, the Working Interest Owner has advised the Trust that approximately 66,709 Mcf have been overtaken by the

13

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Working Interest Owner from this property as of April 30, 2002. The Trust's share of this overtake position as of April 30, 2002 is approximately 16,667 Mcf. Accordingly, gas revenues
from this property may be decreased in future periods while underproduced parties recoup their share of the gas imbalance. ChevronTexaco has advised the Trust that sufficient gas reserves exist on
Ship Shoal 182/183 for under produced parties to recoup their share of the gas imbalance on this property. Capital expenditures decreased from $783,194 in the second quarter of 2001 to $330,463 in the
second quarter of 2002 primarily due to normalization after the completion of the I-1 developmental well and platform upgrade of a pipeline pump panel and digital pressure controls. Operating expenses
increased slightly from $379,740 in the second quarter of 2001 to $381,997 for the same period in 2002.

Eugene
Island 339 crude oil revenues decreased from $1,444,056 in the second quarter of 2001 to $1,064,366 in the second quarter of 2002, primarily due to a significant decrease in the
average price of crude oil from $32.73 per barrel in the second quarter of 2001 to $19.95 per barrel in the second quarter of 2002. This decrease in price was partially offset by an increase in crude
oil production from 44,114 barrels in the second quarter of 2001 to 53,355 barrels in the second quarter of 2002. The increase in crude oil production was due primarily to increased production on the
B-7 well offset by field declines. Gas revenues decreased from $441,270 in the second quarter of 2001 to $99,308 in the second quarter of 2002, primarily due to a decrease in the average
natural gas sales price from $7.21 per Mcf in the second quarter of 2001 to $2.82 in the second quarter of 2002. The Working Interest Owner has advised the Trust that there is an overtake imbalance
position of approximately 13,673 Mcf on this property as of November 30, 2000. The Trust's share of this overtake position is approximately 3,418 Mcf. Accordingly, gas revenues from this
property may be reduced in future periods while under produced parties recoup their share of the gas imbalance. ChevronTexaco has advised the Trust that sufficient gas reserves exist on the Eugene
Island 339 for underproduced parties to recoup their share of the gas imbalance on this property. The gas from this property is currently committed to Dynegy at a calculated price based on the monthly
Inside FERC Tennessee-Louisiana Zone 1 Index. Capital expenditures increased to $186,688 in the second quarter of 2002 from $17,030 in the second quarter of 2001 due to a B7 side track workover and an
inspection program. Operating expenses decreased from $299,967 in the second quarter of 2001 to $37,477 in the second quarter of 2002, due to fewer full-time employees being used and allocated to this
property base beginning in January 2002.

West
Cameron 643 gas revenues decreased from $1,116,815 in the second quarter of 2001 to $57,046 in the second quarter of 2002, primarily due to a decrease in gas volumes from 198,857
second quarter of 2001 to 22,753 in the second quarter of 2002 and the significant decrease in the average price received for natural gas from $5.62 per Mcf in the second quarter of 2001 to $2.51 per
Mcf in the second quarter of 2002. The decrease in volumes was primarily due to the Columbia Gulf Gas pipeline leak and by the B8 sidetrack shut in due to water production. The gas from West Cameron
643 is currently committed to Texaco Natural Gas Inc. ("TNGI"). TNGI is a wholly owned affiliate of TEPI. TNGI purchases natural gas from TEPI and
resells such gas to a variety of third-party customers at a variety of downstream delivery points. The prices that TNGI pays TEPI for the gas production is based on the actual sale prices that TNGI
receives from its third-party customers less the actual transportation 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. The Working Interest Owner has advised the Trust that approximately 4,940 Mcf have been overtaken by the Working Interest Owner from this property as of January 2002. The
Trust's share of this overtake position is approximately 1,235 Mcf. Accordingly, gas revenues from this property may be reduced in future periods while under produced parties recover their share of
the gas imbalance.

14

---

Operating expenses decreased from $228,960 in the second quarter of 2001 to $172,778 for the same period in 2002, primarily due to less employees. Capital expenditures decreased from $78,061 in the
second quarter of 2001 to $52,624 as compared to the same period in 2002.

East
Cameron 371/381 crude oil revenues decreased from $51,349 in the second quarter of 2001 to $27,066 in the second quarter of 2002 in part due to a decrease in the average crude oil
price from $27.96 per barrel in the second quarter of 2001 to $23.56 per barrel in the second quarter of 2002. Also, crude oil production decreased from 1,837 barrels in the second quarter of 2001 to
1,149 barrels for the same period in 2002. Gas revenues decreased from $223,268 in the second quarter of 2001 to $42,059 in the second quarter of 2002. This significant decrease was primarily due to
natural field declines. Increased water production is also causing a decrease in gas production and gas realization is lower per Mcf. Gas volumes decreased from 35,988 Mcf in the second quarter of
2001 to 16,603 Mcf in the second quarter of 2002. The average price received for natural gas decreased from $6.20 per Mcf in the second quarter of 2001 to $2.53 per Mcf in the second quarter of 2002.
Capital expenditures were $4.22 in the second quarter of 2001 and there were $0 in the second quarter of 2002. Operating expenses increased from $25,489 in the second quarter of 2001 to $47,498 in the
second quarter of 2002, due to wrong location charged in first quarter.

Six Months Ended June 30, 2002 and 2001

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

Ship
Shoal 182/183 crude oil revenues decreased from $6,271,594 in the first six months of 2001 to $4,295,694 in the first six months of 2002, primarily due to a decrease in the average
price of crude oil from $30.20 per barrel in the first six months of 2001 to $20.65 per barrel in the first six months of 2002. Crude oil production increased slightly from 207,645 barrels in the six
months of 2001 to 209,464 barrels in the six months of 2002. Gas revenues decreased from $1,627,175 in the first six months of 2001 to $377,924 in the first six months of 2002 primarily due to a
significant decrease in the average
natural gas sales price from $7.01 per Mcf in the first six months of 2001 to $2.42 per Mcf in the first six months of 2002. Gas volumes decreased from 232,280 Mcf in the first six months of 2001 to
152,877 Mcf in the first six months of 2002, primarily as a result of the disappointing results from the I-1 well and B15 being taken off production for two weeks. Capital expenditures
increased from $855,144 in the first six months of 2001 to $3,643,405 in the same period of 2002 primarily due to normalization after the completion of the I-1 developmental well and platform upgrade
of a pipeline pump panel and digital pressure controls. Operating expenses increased from $707,067 for the first six months of 2001 to $760,794 for the first six months of 2002.

Eugene
Island 339 crude oil revenues decreased from $2,956,547 in the first six months of 2001 to $1,581,621 in the first six months of 2002, primarily due to a decrease in the average
price of crude oil from $31.08 per barrel in the first six months of 2001 to $19.03 per barrel in the first six months of 2002. Crude oil production decreased from 95,499 barrels in the first six
months of 2001 to 81,922 barrels in the first six months of 2002 due primarily to continued natural production declines of these properties. Gas revenues decreased from $528,602 in the first six
months of 2001 to $68,243 in the first six months of 2002, primarily due to a significant decrease in the average natural gas sales price from $7.37 per Mcf in the first six months of 2001 to $2.82 in
the first six months of 2002. Capital expenditures increased from $82,338 in the first six months of 2001 to $503,275 in the first six months of 2002 due to a B7 sidetrack workover and an inspection
program. Operating expenses decreased from $578,621 in the first six months of 2001 to

15

---

$223,564 in the first six months due to fewer full-time employees being used and allocated to this property beginning in January 2002.

West
Cameron 643 gas revenues decreased from $2,876,053 in the first six months of 2001 to $101,657 in the first six months of 2002, primarily due to a decrease in average natural gas
sales price from $6.30 per Mcf in the first six months of 2001 to $2.45 per Mcf in the first six months of 2002. The decrease in revenues was further impacted by the decrease in gas volumes
from 450,957 Mcf in the first six months of 2001 to 41,479 Mcf for the same period in 2002. The decrease in volumes was primarily due to a Columbia Gulf Gas pipeline leak and by the B8
sidetrack being shut in due to water production. Operating expenses decreased from $578,621 in the first six months of 2001 to $410,456 for the first six months of 2002, primarily due to fewer
employees. Capital expenditures increased from $82,338 in the first six months of 2001 to $430,021 in the first six months of 2002.

East
Cameron 371/381 crude oil revenues decreased from $104,390 in the first six months of 2001 to $43,584 in the first six months of 2002 due in part to a decrease in the average price
of crude oil from $29.56 per barrel in the first six months of 2001 to $21.67 per barrel in the same period in 2002. Crude oil production also decreased from 3,531 barrels in the first six months of
2001 to 2,011 barrels in the first six months of 2002. Gas revenues decreased from $639,481 in the first six months of 2001 to $99,102 in the first six months of 2002, due in part to a decrease in the
average natural gas sales price from $6.83 per Mcf in the first six months of 2001 to $2.76 Mcf in the first six months of 2002. Gas
volumes also decreased from 97,630 Mcf in the first six months of 2001 to 35,745 in the first six months of 2002. Capital expenditures decreased from $1,277 in the first six months of 2001 to $0 in
the first six months of 2002. Operating expenses increased from $43,763 in the first six months of 2001 to $102,407 in the first six months of 2002.

Future Net Revenues and Termination of the Trust

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

16

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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 six months of 2001, there was a net deposit of funds into the Special Cost Escrow Account. The Trust's share of the funds deposited was approximately $399,376. 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 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 decrease in the estimate of projected
capital expenditures, production costs and abandonment costs of the Royalty Properties. As of June 30, 2002, approximately $4,852,963 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

17

---

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)                             |  |                                                   | 156,917  
|Natural gas and gas products (Mcf)                          |  |                                                   | 220,205  
|Crude oil and condensate average price, per bbl             |  | $                                                 | 21.64    
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                 | 2.41     
|Crude oil and condensate revenues                           |  | $                                                 | 3,395,701
|Natural gas and gas products revenues                       |  |                                                   | 493,866  
|Production expenses                                         |  |                                                   | (685,174 
|Capital expenditures                                        |  |                                                   | (582,635 
|Undistributed Net Income(2)                                 |  |                                                   | (59,771  
|Refund of escrowed special costs                            |  |                                                   | 728,761  
|                                                            |  |                                                   |          
|Net Proceeds                                                |  | $                                                 | 3,290,748
|Royalty interest                                            |  |                                                   | x25%     
|                                                            |  |                                                   |          
|Partnership share                                           |  | $                                                 | 822,687  
|Trust interest                                              |  |                                                   | x99.99%  
|                                                            |  |                                                   |          
|Trust share                                                 |  | $                                                 | 822,605  
|                                                            |  |                                                   |          

---

18

---

|                                                            |  | Royalty Properties
Six Months Ended
June 30,(1) |           
|----------------------------------------------------------- |  | ----------------------------------------------- | ----------
|
|Crude oil and condensate (bbls)                             |  |                                                 | 305,311   
|Natural gas and gas products (Mcf)                          |  |                                                 | 485,692   
|Crude oil and condensate average price, per bbl             |  | $                                               | 20.15     
|Natural gas average price, per Mcf (excluding gas products) |  | $                                               | 2.33      
|Crude oil and condensate revenues                           |  | $                                               | 6,163,086 
|Natural gas and gas products revenues                       |  |                                                 | 1,104,100 
|Production expenses                                         |  |                                                 | 1,200,778 
|Capital expenditures                                        |  |                                                 | (4,622,893
|Undistributed Net Income(2)                                 |  |                                                 | (113,553  
|Refund (Provision for) escrowed special costs               |  |                                                 | 2,387,418 
|                                                            |  |                                                 |           
|Net Proceeds                                                |  | $                                               | 3,717,380 
|Royalty interest                                            |  |                                                 | x25%      
|Partnership share                                           |  | $                                               | 929,345   
|Trust interest                                              |  |                                                 | x99.99%   
|                                                            |  |                                                 |           
|Trust share                                                 |  | $                                               | 929,252   
|                                                            |  |                                                 |           

---

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, 2001. Reference is
also made to Note 2 of the Notes to Financial Statements included in Item 1 of this Form 10-Q.

19

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PART II  OTHER INFORMATION

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

(a) Exhibits

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

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

(b) Reports on Form 8-K

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

20

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SIGNATURES

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

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

Date:
August 14, 2002

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

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TEL
OFFSHORE
TRUSTFederal Income Tax
Information2002

---

TEL OFFSHORE TRUST  EIN 76-6004064  SCHEDULE B  Second Quarter 2002    Tax Information per Unit  (4,751,510 Units)

|                   |  | PARTNERSHIP
ITEMS PER UNIT |          | TRUST ITEMS PER UNIT |        
|------------------ |  | -------------------------- | -------- | -------------------- | -------
|
|March 29, 2002     |  | $                          | 0.022445 |                      | 0.6997%
|June 28, 2002      |  |                            | 0.173125 |                      | 5.3970%
|September 29, 2002 |  |                            | N.A.     |                      | N.A.   
|December 29, 2002  |  |                            | N.A.     |                      | N.A.   
|                   |  |                            |          |                      |        
|Year to date       |  | $                          | 0.195570 |                      | 6.0967%
|                   |  |                            |          |                      |        

Summary of Taxable Income

Per UnitRoyalty Income

$
0.195570Interest Income


0.000834Depletion Deduction


(0.003819
)Administrative Expense Deduction


(0.076394
)(Increase)/Decrease in Reserve


(0.024503
)Net Amount

$
0.091689


---

Tax Basis of Units and Royalty*

|Basis Assigned to TEL Offshore Trust Units  1/1/83             |  | $ | 6.750000  |  
|--------------------------------------------------------------- |  | - | --------- | -
|Basis Allocated to Offshore II Company (Sold December 17, 1984) |  |   | (0.120000 | )
|                                                                |  |   |          
|Royalty Basis 1/1/83                                            |  |   | 6.630000  |  
|Depletion Year 1983                                             |  |   | (0.769366 | )
|                                                                |  |   |          
|Royalty Basis 1/1/84                                            |  |   | 5.860634  |  
|Depletion Year 1984                                             |  |   | (1.203489 |  
|                                                                |  |   |          
|Royalty Basis 1/1/85                                            |  |   | 4.657145  |  
|Depletion Year 1985                                             |  |   | (1.126563 | )
|                                                                |  |   |          
|Royalty Basis 1/1/86                                            |  |   | 3.530582  |  
|Depletion Year 1986                                             |  |   | (0.555675 | )
|                                                                |  |   |          
|Royalty Basis 1/1/87                                            |  |   | 2.974907  |  
|Depletion Year 1987                                             |  |   | (1.424231 | )
|                                                                |  |   |          
|Royalty Basis 1/1/88                                            |  |   | 1.550676  |  
|Depletion Year 1988                                             |  |   | (0.384321 | )
|                                                                |  |   |          
|Royalty Basis 1/1/89                                            |  |   | 1.166355  |  
|Depletion Year 1989                                             |  |   | (0.241515 | )
|                                                                |  |   |          
|Royalty Basis 1/1/90                                            |  |   | 0.924840  |  
|Depletion Year 1990                                             |  |   | (0.141097 | )
|                                                                |  |   |          
|Royalty Basis 1/1/91                                            |  |   | 0.682743  |  
|Depletion Year 1991                                             |  |   | (0.092228 | )
|                                                                |  |   |          
|Royalty Basis 1/1/92                                            |  |   | 0.590515  |  
|Depletion Year 1992                                             |  |   | (0.058181 | )
|                                                                |  |   |          
|Royalty Basis 1/1/93                                            |  |   | 0.532334  |  
|Depletion Year 1993                                             |  |   | (0.079729 | )
|                                                                |  |   |          
|Royalty Basis 1/1/94                                            |  |   | 0.452605  |  
|Depletion Year 1994                                             |  |   | (0.148288 | )
|                                                                |  |   |          
|Royalty Basis 1/1/95                                            |  |   | 0.304317  |  
|Depletion Year 1995                                             |  |   | (0.064972 | )
|                                                                |  |   |          
|Royalty Basis 1/1/96                                            |  |   | 0.239345  |  
|Depletion Year 1996                                             |  |   | (0.024448 | )
|                                                                |  |   |          
|Royalty Basis 1/1/97                                            |  |   | 0.214897  |  
|Depletion Year 1997                                             |  |   | (0.048705 | )
|                                                                |  |   |          
|Royalty Basis 1/1/98                                            |  |   | 0.166192  |  
|Depletion Year 1998                                             |  |   | (0.031658 | )
|                                                                |  |   |          
|Royalty Basis 1/1/99                                            |  |   | 0.134534  |  
|Depletion Year 1999                                             |  |   | (.024322  | )
|                                                                |  |   |          
|Royalty Basis 1/1/00                                            |  |   | 0.110212  |  
|Depletion Year 2000                                             |  |   | (.035962  | )
|                                                                |  |   |          
|Royalty Basis 1/1/01                                            |  |   | 0.074250  |  
|Depletion Year 2001                                             |  |   | (0.011616 | )
|                                                                |  |   |          
|Royalty Basis 1/1/02                                            |  | $ | 0.062634  |  
|Depletion Through Second Quarter 2002                           |  |   | (0.003819 | )
|                                                                |  |   |          
|Royalty Basis 6/30/2002                                         |  | $ | 0.058815  |  
|                                                                |  |   |          

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