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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                              -------------------

                                   FORM 10-Q

<Table>
<S>              <C>
/X/              QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                 SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD
                 ENDED MARCH 31, 2002
</Table>

                                       OR

<Table>
<S>              <C>
/ /              TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                 SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD
                 FROM TO
</Table>

                         COMMISSION FILE NUMBER: 0-6910

                               -----------------

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

<Table>
<S>                                            <C>
                 TEXAS                                      76-6004064
       (State of Incorporation,                          I.R.S. Employer
           or Organization)                            Identification No.)

          JPMORGAN CHASE BANK
     INSTITUTIONAL TRUST SERVICES
           700 LAVACA STREET
             AUSTIN, TEXAS
         (Address of Principal
          Executive Offices)
                                                              78701
                                                            (Zip Code)
</Table>

       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 May 10, 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 principal risks and Cautionary Statements is
also included in the Trust's Form 10-K under "Business--Principal Trust Risk
Factors." All subsequent written and oral forward-looking statements
attributable to the Trust or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.

                                       i
<Page>
                         PART I--FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

                               TEL OFFSHORE TRUST
               STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<Table>
<Caption>
                                                               MARCH 31,    DECEMBER 31,
                                                                 2002           2001
                                                              -----------   ------------
                                                              (UNAUDITED)
<S>                                                           <C>           <C>
ASSETS
Cash and cash equivalents...................................  $  923,918     $1,183,592
Net overriding royalty interest in oil and gas properties,
  net of accumulated amortization of $28,048,739 and
  $28,047,080, respectively.................................     218,916        220,575
                                                              ----------     ----------
Total assets................................................  $1,142,834     $1,404,167
                                                              ==========     ==========

LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders........................  $        0     $  204,621
Reserve for future Trust expenses...........................     923,918        978,971
Commitments and contingencies (Note 7)
Trust corpus (4,751,510 Units of beneficial interest
  authorized and outstanding)...............................     218,916        220,575
                                                              ----------     ----------
Total liabilities and Trust corpus..........................  $1,142,834     $1,404,167
                                                              ==========     ==========
</Table>

                       STATEMENTS OF DISTRIBUTABLE INCOME
                                  (UNAUDITED)

<Table>
<Caption>
                                                                THREE MONTHS ENDED
                                                                     MARCH 31,
                                                              -----------------------
                                                                2002         2001
                                                              ---------   -----------
<S>                                                           <C>         <C>
Royalty income..............................................  $ 106,647   $ 1,518,643
Interest income.............................................        941        36,909
                                                              ---------   -----------
                                                                107,588     1,555,552
Decrease in reserve for future Trust expenses...............     55,053       138,513
General and administrative expenses.........................   (162,641)      (97,061)
                                                              ---------   -----------
Distributable income........................................  $       0   $ 1,597,004
Distributions per Unit (4,751,510 Units)....................  $ .000000   $   .336105
</Table>

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

                                       1
<Page>
                     STATEMENTS OF CHANGES IN TRUST CORPUS
                                  (UNAUDITED)

<Table>
<Caption>
                                                                THREE MONTHS ENDED
                                                                    MARCH 31,
                                                              ----------------------
                                                                2002        2001
                                                              --------   -----------
<S>                                                           <C>        <C>
Trust corpus, beginning of period...........................  $220,575   $   269,081
Distributable income........................................         0     1,597,004
Distribution payable to Unit holders........................         0    (1,597,004)
Amortization of net overriding royalty interest.............    (1,659)      (14,865)
                                                              --------   -----------
Trust corpus, end of period.................................  $218,916   $   254,216
                                                              ========   ===========
</Table>

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

                                       2
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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.

                                       3
<Page>
                               TEL OFFSHORE TRUST

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

                                  (UNAUDITED)

NOTE 1 -- TRUST ORGANIZATION (CONTINUED)
    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.

    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;
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).

                                       4
<Page>
                               TEL OFFSHORE TRUST

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

                                  (UNAUDITED)

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, 2001.

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

       (a) Royalty income is recorded when received, including the effect of
           overtaken or undertaken positions, by the Corporate Trustee on the
           last business day of each calendar quarter; and

       (b) Trust general and administrative expenses are recorded when paid,
           except for the cash reserved for future general and administrative
           expenses, as discussed in Note 6.

    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 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.

                                       5
<Page>
                               TEL OFFSHORE TRUST

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

                                  (UNAUDITED)

NOTE 2 -- BASIS OF ACCOUNTING (CONTINUED)
    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.

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.

                                       6
<Page>
                               TEL OFFSHORE TRUST

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

                                  (UNAUDITED)

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 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 2001, there was a net deposit of funds into the Special
Cost Escrow Account. The Trust's share of the funds deposited was approximately
$423,125. 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 $414,664. 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, 2002, approximately
$5,293,550 remained in the Special Cost Escrow Account.

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

NOTE 6 -- EXPENSE RESERVE

    The Trust made a determination in 1998 to maintain a cash reserve equal to
three times the average expenses of the Trust during each of the past three
years to provide for future administrative expenses in connection with the
winding up of the Trust. The reserve amount for 2001 was $978,971. The excess

                                       7
<Page>
                               TEL OFFSHORE TRUST

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

                                  (UNAUDITED)

NOTE 6 -- EXPENSE RESERVE (CONTINUED)
amount in the reserve January 1, 2001, 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. However, the Trust used $161,700 from the Trust's cash reserve
account in the first quarter of 2002 to pay the Trust's general and
administrative expenses as insufficient royalty income was received by the Trust
during that quarter.

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 $608,598 has been recovered from the Trust by the Working Interest
Owner through the first 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 attributable 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 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.

                                       8
<Page>
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:

       (a) Royalty income is recorded when received, including the effect of
           overtaken or undertaken positions, by the Corporate Trustee on the
           last business day of each calendar quarter; and

       (b) Trust general and administrative expenses are recorded when paid,
           except for the cash reserved for future general and administrative
           expenses.

    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, 2002 AND 2001

    There were no distributions for the three months ended March 31, 2002.
Distributions to Unit holders for the three months ended March 31, 2001 amounted
to $1,597,004 or $.336105 per Unit.

    Gas revenues decreased $3,476,404, or 86%, to $545,405 in the first quarter
of 2002 from $4,021,809 in the first quarter of 2001, primarily due to a 68%
decrease in the average price received for natural gas to $2.25 per Mcf in the
first quarter of 2002 from $6.98 per Mcf in the first quarter of 2001.
Additionally, gas volumes decreased by 58% to 242,603 Mcf in the first quarter
of 2002 from 576,302 Mcf in the first quarter of 2001.

    Crude oil and condensate revenues decreased $2,229,905, or 45%, to
$2,767,385 in the first quarter of 2002 as compared to $4,997,290 in the same
period in 2001, primarily due to a 39% decrease in the average price of crude
oil and condensate from $30.35 per barrel in the first quarter of 2001 to $18.65
per barrel in the same quarter of 2002. Additionally, crude oil and condensate
volume decreased 10% from the first quarter of 2001 to the first quarter of
2002.

    The Trust's share of capital expenditures increased approximately
$3,844,120, from $196,139 in the first quarter of 2001 to $4,040,258 in the
first quarter of 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 ShipShoal 182/183 property.

    For the first quarter of 2002, the Trust had undistributed net income of
$53,782. 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). The undistributed net income for the first

                                       9
<Page>
quarter of 2002 was primarily related to the loss carryforward referred to above
on the Eugene Island 348 property.

    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 $414,664, compared to a net deposit of funds into the Special Cost
Escrow Account of $423,125 net to the Trust in the first 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.

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 of $138,513 in the
reserve on January 1, 2002 was distributed to Unit holders in the first quarter
of 2001. The reserve amount for 2002 was calculated to be $996,993. However, the
Trust used $161,700 from the Trust's cash reserve account in the first quarter
of 2002 to pay the Trust's general and administrative expenses as insufficient
Royalty income was received by the Trust during that quarter.

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 MARCH 31, 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 $3,199,913 in the first
quarter of 2001 to $2,104,381 in the first quarter of 2002, primarily due to an
decrease in the average crude oil price from $30.70 per barrel in the first
quarter of 2001 to $18.70 per barrel for the same period in 2002. The decrease
in the average crude oil price was partially offset by an increase in crude oil
production from 104,228 barrels in the first quarter of 2001 to 112,516 in the
first quarter of 2002. The increase in crude oil production was due primarily to
a new I-1 well at the start of the first quarter. Gas revenues decreased from
$996,265 in the first quarter of 2001 to $271,324 in the first quarter of 2002
primarily due to an

                                       10
<Page>
decrease in the average natural gas sales price from $7.46 per Mcf in the first
quarter of 2001 to $2.56 per Mcf for the same period in 2002. Additionally, the
natural gas production decreased from 133,481 Mcf in the first quarter of 2001
to 105,917 Mcf in the first quarter of 2002. The decrease in gas volumes was
primarily a result of poor weather that delayed work on the platform. 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
69,818 Mcf have been overtaken by the Working Interest Owner from this property
as of January 31, 2002. The Trust's share of this overtake position as of
January 31, 2002 is approximately 17,455 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 underproduced
parties to recoup their share of the gas imbalance on this property. Capital
expenditures inecreased from $71,950 in the first quarter of 2001 to $3,312,942
in the first quarter of 2002 primarily due to an upgrade of pipeline pump panel
and digital pressure controls for the I-1 development well. Operating expenses
increased slightly from $327,327 in the first quarter of 2001 to $378,797 for
the same period in 2002.

    Eugene Island 339 crude oil revenues decreased from $1,512,491 in the first
quarter of 2001 to $517,255 for the same period in 2002 due to a decrease in
volumes from 51,385 in the first quarter of 2001 to 28,567 barrels in the first
quarter of 2002 due primarily to the wells watering out. In addition, the
average crude oil price decreased from $29.43 per barrel in the first quarter of
2001 to $18.11 per barrel in the first quarter of 2002. Gas revenues decreased
from $178,630 in the first quarter 2001 to ($31,065) in the first quarter of
2002 primarily due to a decrease in natural gas volumes from 20,591 Mcf in the
first quarter of 2001 to 10,241 Mcf in the first quarter of 2002 coupled with a
($81,640) estimate adjustment. The Working Interest Owner has advised the Trust
that there is an overtake imbalance position of approximately 5,281 Mcf on this
property as of January, 2002. The Trust's share of this overtake position is
approximately 1,320 Mcf. Accordingly, gas revenues from this property may be
reduced in future periods while underproduced 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 from $65,308 in
the first quarter of 2001 to $316,587 in the first quarter of 2002 due to the B7
side track workover and inspection program. Operating expenses decreased from
$278,654 in the first quarter of 2001 to $186,087 in the first quarter of 2002.

    West Cameron 643 gas revenues decreased from $1,759,238 in the first quarter
of 2001 to $44,611 in the first quarter of 2002. This is due to the decrease in
the average price received for natural gas from $6.98 per Mcf in the first
quarter of 2001 to $2.38 per Mcf in the first quarter of 2002, and a significant
decrease in gas volumes from 252,100 Mcf in the first quarter of 2001 to 18,726
Mcf for the same period in 2002. The decrease in volumes was primarily due to
the Columbia Gulf Gas pipeline leak and the A and B platforms temporarily going
off production. The gas from West Cameron 643 is currently committed to Texaco
Natural Gas Inc. ("TNGI"). TNGI is a wholly owned 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. The Working Interest Owner
has

                                       11
<Page>
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 underproduced parties
recover their share of the gas imbalance. Operating expenses decreased from
$335,565 in the first quarter of 2001 to $237,678 for the same period in 2002,
and capital expenditures increased from $28,866 in the first quarter of 2001 to
$377,397 for the same period in 2002.

    East Cameron 371/381 crude oil revenues decreased from $53,041 in the first
quarter of 2001 to $16,518 in the first quarter of 2002 primarily due to a
decrease in the average crude oil price from $31.31 per barrel in the first
quarter of 2001 to $19.15 per barrel in the first quarter of 2002. Also, crude
oil production decreased from 1,694 barrels in the first quarter of 2001 to 862
barrels for the same period in 2002. Gas revenues decreased from $416,213 in the
first quarter of 2001 to $57,043 in the first quarter of 2002. This is due to a
decrease in gas volumes from 53,571 Mcf in the first quarter of 2001 to 19,142
Mcf for the same period in 2002 and a decrease in the average price received for
natural gas from $7.77 per Mcf in the first quarter of 2001 to $2.98 per Mcf in
the first quarter of 2002. Capital expenditures were $(1,281) in the first
quarter of 2001 and were $0 in the first quarter of 2002. Operating expenses
increased from $18,274 in the first quarter of 2001 to $54,909 in the first
quarter 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 were
approximately $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.

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

                                       12
<Page>
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 2001, there was a net deposit of funds
into the Special Cost Escrow Account. The Trust's share of the funds deposited
was approximately $423,125. 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 $414,664. 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, 2002, approximately
$5,293,550 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

                                       13
<Page>
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.

<Table>
<Caption>
                                                                 ROYALTY PROPERTIES
                                                                 THREE MONTHS ENDED
                                                                    MARCH 31,(1)
                                                              -------------------------
                                                                 2002          2001
                                                              -----------   -----------
<S>                                                           <C>           <C>
Crude oil and condensate (bbls).............................      148,409       164,657
Natural gas and gas products (Mcf)..........................      265,847       603,668
Crude oil and condensate average price, per bbl.............  $     18.65   $     30.35
Natural gas average price, per Mcf (excluding gas
  products).................................................  $      2.25   $      6.98
Crude oil and condensate revenues...........................  $ 2,767,385   $ 4,997,290
Natural gas and gas products revenues.......................      610,234     4,109,267
Production expenses.........................................     (515,604)     (978,491)
Capital expenditures........................................   (4,040,258)     (196,139)
Undistributed net loss (income)(2)..........................      (53,782)     (164,248)
(Provision for) Refund of escrowed special costs............    1,658,657    (1,692,500)
                                                              -----------   -----------
NET PROCEEDS................................................  $   426,632   $ 6,075,179
Royalty interest............................................         x25%          x25%
                                                              -----------   -----------
Partnership share...........................................  $   106,658   $ 1,518,795
Trust interest..............................................      x99.99%       x99.99%
                                                              -----------   -----------
Trust share.................................................  $   106,647   $ 1,518,643
                                                              ===========   ===========
</Table>

---------

(1) The amounts for the three months ended March 31, 2002 and 2001 represent
    actual production for the periods November 2001 through January 2002, and
    November 2000 through January 2001, respectively.

(2) Undistributed net loss represents negative Net Proceeds generated during the
    respective period. An undistributed net loss is carried forward and offset,
    in future periods, by positive Net Proceeds earned by the related Working
    Interest Owner(s). Undistributed net income represents positive Net
    Proceeds, generated during the respective period, that were applied to an
    existing loss carryforward. As of March 31, 2002, the loss carryforward was
    $261,608 ($65,402 net to the Trust).

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.

                                       14
<Page>
                          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.)

<Table>
<Caption>
                                                                                                    SEC FILE OR
                                                                                                    REGISTRATION   EXHIBIT
                                                                                                       NUMBER       NUMBER
                                                                                                    ------------   --------
    <S>                     <C>         <C>                                                         <C>            <C>
    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 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)
</Table>

(B) REPORTS ON FORM 8-K

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

                                       15
<Page>
                                   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.

<Table>
<S>                                         <C>        <C>
                                            TEL OFFSHORE TRUST

                                            By:        JPMorgan Chase Bank, Corporate Trustee

                                            By:                     /s/ MIKE ULRICH
                                                       -----------------------------------------
                                                                      MIKE ULRICH
                                                                     VICE PRESIDENT
</Table>

Date: May 15, 2002

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.

                                       16
<Page>
                                      TEL
                                    OFFSHORE
                                     TRUST
                               FEDERAL INCOME TAX
                                  INFORMATION
                                      2002
<Page>
                               TEL OFFSHORE TRUST
                                 EIN 76-6004064
                                   SCHEDULE B
                               FIRST QUARTER 2002
                            TAX INFORMATION PER UNIT
                               (4,751,510 UNITS)

<Table>
<Caption>
                                         PARTNERSHIP
                                        ITEMS PER UNIT                   TRUST ITEMS PER UNIT
                                  --------------------------   -----------------------------------------
                                              DEPLETION AS A                                **(INCREASE)
                                   ROYALTY      PERCENT OF     INTEREST    ADMINISTRATIVE   DECREASE IN
          RECORD DATE              INCOME     ROYALTY BASIS     INCOME        EXPENSE         RESERVE
          -----------             ---------   --------------   ---------   --------------   ------------
<S>                               <C>         <C>              <C>         <C>              <C>
March 31, 2002..................  $0.022445       0.6997%      $0.000198     $0.034229       $0.030288
June 30, 2002...................   0.000000       0.0000%       0.000000      0.000000        0.000000
September 29, 2002..............   0.000000       0.0000%       0.000000      0.000000        0.000000
December 29, 2002...............   0.000000       0.0000%       0.000000      0.000000        0.000000
                                  ---------       -------      ---------     ---------       ---------
Year to date....................  $0.319613       5.2875%      $0.007768     $0.020427       $0.029151
                                  =========       =======      =========     =========       =========
</Table>

                           SUMMARY OF TAXABLE INCOME

<Table>
<Caption>
                                                               PER UNIT
                                                              ----------
<S>                                                           <C>
Royalty Income..............................................  $ 0.022445
Interest Income.............................................    0.000198
Depletion Deduction.........................................   (0.000438)
Administrative Expense Deduction............................   (0.034229)
(Increase)/Decrease in Reserve..............................    0.030288
                                                              ----------
Net Amount..................................................  $ 0.018264
                                                              ==========
</Table>

**  Increase or decrease in the reserve amount has no tax effect and is shown
    for information purposes only.
<Page>
                        TAX BASIS OF UNITS AND ROYALTY*

<Table>
<S>                                                           <C>
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 First Quarter 2002........................   (0.000438)
                                                              ----------
Royalty Basis 3/31/02.......................................  $ 0.062196
                                                              ==========
</Table>

----------
*   For Unit holders who acquired their Units in the initial distribution in
    January of 1983.

    For Unit holders acquiring Units other than in the initial distribution from
    Tenneco Offshore Company and prior to December 17, 1984, their royalty basis
    should be equal to 98.2533% of the purchase price of such Units, less
    depletion taken from the date of purchase.

    Unit holders who acquired their Units after December 17, 1984 will have a
    basis in the royalty equal to the purchase price of such Units, less
    depletion taken from the date of purchase.