UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549



FORM 10-Q

ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended June 30, 2008oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period
from                                  toCommission File Number: 0-6910




TEL OFFSHORE TRUST(Exact name of registrant as specified in its charter)

Texas(State or other jurisdiction of
incorporation or organization)

76-6004064(I.R.S. Employer
Identification No.)The Bank of New York Trust
Company, N.A., Trustee
919 Congress Avenue
Austin, Texas(Address of principal executive offices)

78701(Zip Code)(800) 852-1422(Registrant's telephone number, including area code)


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 ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filer o

Non-accelerated filer ý (Do not check if a smaller reporting company)

Smaller reporting company o


Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)
Yes o No ý

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of August 14,
2008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 Annual Report on Form 10-K for the year ended
December 31, 2007 under Part I, Item 1A. "Risk Factors." All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are
expressly qualified in their entirety by the Cautionary Statements.

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PART IFINANCIAL INFORMATION

Item 1.    Financial Statements.

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

June 30, 2008

December 31, 2007AssetsCash and cash equivalents

$
4,755,553

$
5,136,437Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,232,053 and $28,227,458, respectively


35,602


40,197Total assets

$
4,791,155

$
5,176,634Liabilities and Trust CorpusDistribution payable to Unit holders

$
2,619,375

$
3,252,711Reserve for future Trust expenses


2,136,178


1,883,726Commitments and contingenciesTrust corpus (4,751,510 Units of beneficial interest authorized and outstanding)


35,602


40,197Total liabilities and Trust corpus

$
4,791,155

$
5,176,634


STATEMENTS OF DISTRIBUTABLE INCOME        (Unaudited)

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007Royalty income

$
2,750,990

$
2,415,521

$
7,818,511

$
3,932,205Interest income


8,929


18,216


20,189


36,2552,759,919


2,433,737


7,838,700


3,968,460(Increase) decrease in reserve for future Trust expenses


109,269


(97,276
)

(252,452
)

(351,303
)General and administrative expenses


(249,813
)

(282,528
)

(497,830
)

(395,650
)Distributable income

$
2,619,375

$
2,053,933

$
7,088,418

$
3,221,507Distributions per Unit (4,751,510 Units)

$
.551272

$
.432270

$
1.491824

$
.677997


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

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STATEMENTS OF CHANGES IN TRUST CORPUS        (Unaudited)

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007Trust corpus, beginning of period

$
37,609

$
49,533

$
40,197

$
53,506Distributable income


2,619,375


2,053,933


7,088,418


3,221,504Distribution payable to Unit holders


2,619,375


2,053,933


7,088,418


3,221,504Amortization of net overriding royalty interest


(2,007
)

(3,232
)

(4,595
)

(7,205
)Trust corpus, end of period

$
35,602

$
46,301

$
35,602

$
46,301


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.

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

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

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

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

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

3

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

Effective
January 1, 2000, PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon Energy Production Company L.P. ("Devon"). As a result of such merger, Devon
replaced PennzEnergy as the Working Interest Owner of Eugene Island 348 and Eugene Island 208 properties effective January 1, 2000, and also assumed PennzEnergy's obligations under the
Conveyance with respect to these properties. The abandonment obligations for Eugene Island 348 have been assumed by Maritech Resources, Inc. effective January 1, 2005.

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. Effective May 9, 2005, ChevronTexaco Corporation changed its name to Chevron Corporation.
Accordingly, the properties referred to herein by Chevron and Texaco are each now controlled by subsidiaries of Chevron Corporation.

On
May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371 to Chevron. Chevron sold its interest in East Cameron 371 to Energy Resources
Technology, Inc., effective July 1, 2007. Net proceeds will be calculated for the collective Royalty Properties owned by Chevron after this date.

On
June 6, 2003, Anadarko Petroleum Corporation ("Anadarko") acquired, among other interests, a 25% Working Interest in the East Cameron 354 field subject to the Royalty from
Amerada effective April 1, 2003. As a result of this transaction, Anadarko replaced Amerada as the Working Interest Owner of East Cameron 354 effective July 1, 2003 and also assumed
Amerada's obligations under the conveyance with respect to this property.

Effective
October 1, 2004, Apache Corporation ("Apache") acquired Anadarko's interest in East Cameron 354 and assumed Anadarko's obligations under the conveyance with respect to
this property.

All
of the Royalty Properties continue to be subject to the Royalty, and it is anticipated that the Trust and the Partnership, in general, will continue to operate as if the
above-described sales of the Royalty Properties had not occurred. Chevron, as the Managing General Partner of the Partnership, calculates the Net Proceeds from the Royalty Properties owned by Chevron
and collects financial information relating to the other Royalty Properties from the Working Interest Owners other than Chevron for presentation to the Trust.

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

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except
East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until December 1, 1994, and with respect to the same properties
except West Cameron 643 thereafter; PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene/Devon Island 208 for periods from October 30, 1992 until
October 1, 1995, and with respect to Eugene Island 348 and Eugene Island 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron 371 for periods beginning on or after
December 1, 1994 until May 1, 2002; SONAT with respect to East Cameron 354 for periods beginning on or after October 1, 1995; Amoco with respect to Eugene Island 367 for periods
beginning on or after October 1, 1995; Amerada with respect to East Cameron 354 for periods beginning on or after January 1, 1998 until July 1, 2003; Chevron with respect to West
Cameron 643 on and after May 1, 2002; Chevron with respect to East Cameron 371 on and after May 1, 2002 until July 1, 2007; Anadarko with respect to East Cameron 354 on and after
July 1, 2003 until October 1, 2004; Apache with respect to East Cameron 354 after October 1, 2004; and Energy Resources Technology, Inc. with respect to East Cameron 371 on
and after July 1, 2007).

On
July 18, 2008, Chevron sold its interest in West Cameron 643 to Hilcorp Energy GOM, LLC ("Hilcorp"). Effective August 1, 2008, Hilcorp assumed operations,
reporting and payment responsibilities for West Cameron 643.

The
Trust is currently administered by The Bank of New York Trust Company, N.A., which succeeded JPMorgan Chase Bank, N.A. as the Corporate Trustee, effective October 2, 2006
pursuant to an agreement under which The Bank of New York acquired substantially all of the Corporate Trust business of JPMorgan Chase (formerly known as The Chase Manhattan Bank), and Daniel O.
Conwill, IV, Gary C. Evans and Jeffrey S. Swanson ("Individual Trustees"), as trustees ("Trustees").

Note 2Basis of Accounting

The accompanying unaudited financial information has been prepared by The Bank of New York Trust Company, N.A. ("Corporate Trustee") in
accordance with the instructions to Form 10-Q. The accompanying financial information is prepared on a comprehensive basis of accounting other than accounting principles generally
accepted in the United States of America ("generally accepted accounting principles"). The Corporate Trustee and the Individual Trustees believe that 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. Such adjustments are of a normal and recurring nature. 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,
2007.

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



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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, 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
changes in reserve for future Trust expenses includes both changes of amounts deemed necessary by the Trustees and related distributions, as well as amounts paid from the reserve
during periods when the Trust has insufficient income to pay Trust expenses.

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

The
Special Cost Escrow account (Note 5) is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other
production facilites and for the estimated amount of future capital expenditures on the Royalty Properties. The funds held in the Special Cost Escrow account are not reflected in the financial
statements of the Trust. However, funds deposited to or released from the Special Cost Escrow account are included in Royalty income.

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.

6

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Note 3Net Overriding Royalty Interest

The Royalty entitles the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance,
dated January 1, 1983, provides that the Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal
to 25% of the Net Proceeds from their oil and gas properties for the period. Generally, "Net Proceeds" means the amounts received by the Working Interest Owners from the sale of minerals from the
Royalty Properties less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income
taxes, and a Special Cost Escrow account. The Special Cost Escrow account (See Note 5) is established for the future costs to be incurred to plug and abandon wells, dismantle and remove
platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not include amounts received by the Working
Interest Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future delivery of
gas.

Note 4Distributions to Unit Holders

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

During
2005, Hurricane Katrina and Hurricane Rita caused significant damage to various platforms and third-party transportation systems, which resulted in oil and gas production delays
in our Royalty Properties. During 2006, several of the platforms and facilities on the Royalty Properties were restored, and by the third quarter of 2007 all but one of the platforms and facilities
had been restored. One of the platforms and facilities on Eugene Island was destroyed and has not been restored; efforts to establish a new platform are still in process. Since the hurricanes, overall
production has slowly returned to normal production levels. The Trust may have to fund our share of project costs and other related expenditures that are not covered by insurance of the operator of
the Royalty Properties. The extensive damage caused by these hurricanes led to significant demand for services and supplies for repairs in the offshore Gulf of Mexico, which increased levels of
expenditures. The reduced oil and gas production and increased costs reduced the cash income distributions to unitholders significantly during 2006. During the fourth quarter 2006, the Trust resumed
distributions. The fourth quarter distribution of $1.7 million was paid on January 11, 2007. On March 30, 2007, the Trust announced its first quarter distribution of approximately
$1.2 million. On June 27, 2007, the Trust announced its second quarter distribution of approximately $2.1 million, which was paid on July 9, 2007. On September 27,
2007, the Trust announced its third quarter distribution of approximately $2.8 million, which was paid on October 9, 2007. On December 21, 2007, the Trust announced its fourth
quarter distribution of approximately $3.3 million, which was paid on January 10, 2008. On March 26, 2008, the Trust announced its first quarter distribution of approximately
$4.5 million, which was paid on April 10, 2008. On June 27, 2008, the Trust announced its second quarter distribution of approximately $2.6 million.

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Note 5Special Cost Escrow Account

The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The
Conveyance provides for the reserve of funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well
as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based
on certain factors, including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net profits interest. Deposits into this
account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow"
account. The Trust's share of interest generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated production costs. Special Cost Escrow funds will generally be
utilized to pay Special Costs to the extent there are not adequate current net profits interest to pay such costs. Special Costs that have been paid are no longer included in the Special Cost Escrow
calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of estimated future Special Costs and there is a
Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a Net Revenues
Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow account will also be released
when the balance in such account exceeds 125% of estimated future Special Costs. In the second quarter of 2008 there was a net release of funds from the Special Cost Escrow account; the Trust's share
of the funds released was $41,817. As of June 30, 2008, $5,353,559 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the
financial statements of the Trust.

Chevron,
in its capacity as the Managing General Partner of the Partnership, 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Reserve For Future Trust Expenses

The Trust maintains a cash reserve, equal to approximately 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. During the first six months of 2008, the Trust increased its reserve by $252,452 for a reserve
balance of $2,136,178 as of June 30, 2008. The reserve amount at December 31, 2007 was $1,883,726.

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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.

The
Trustees, including the Corporate Trustee, have no authority over, have not evaluated and make no statement concerning, the internal control over financial reporting of the Working
Interest Owners.

Financial Review

Three Months Ended June 30, 2008 and 2007

There were distributions of $2,619,375 or $0.551272 per Unit to the Unit holders for the three months ended June 30, 2008 as
compared to distributions of $2,053,933 or $0.432270 per Unit to the Unit holders for the same period in 2007.

Crude
oil and condensate revenues increased $2,216,572, or 28%, to $10,080,263 in the second quarter of 2008 as compared to $7,863,691 in the second quarter of 2007, due to a 69%
increase in the average price of crude oil and condensate to $97.73 per barrel in the second quarter of 2008 from $57.83 per barrel in the second quarter of 2007. The increase was partially offset by
a 24% decrease in crude oil and condensate volume to 103,147 barrels in the second quarter of 2008 from 135,984 barrels in the second quarter of 2007.

Gas
revenues increased $783,130, or 34%, to $3,074,648 in the second quarter of 2008 from $2,291,518 in the second quarter of 2007, due to an increase in gas volumes of 22% to 353,503
Mcf in the second quarter of 2008 from 289,797 Mcf in the second quarter of 2007, and a 10% increase in the average price received for natural gas to $8.70 per Mcf in the second quarter of 2008 from
$7.91 per Mcf in the second quarter of 2007. Gas products revenue increased $482,523 to $618,753 in the second

9

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quarter
of 2008 from $136,231 in the second quarter of 2007, due primarily to an increase in production volume of 343,897 gallons to 491,151 gallons in the second quarter of 2008 from 147,254 gallons
in the second quarter of 2007.

The
increase in natural gas volumes and gas products production volumes for the three months ended June 30, 2008 compared to the three months ended June 30, 2007 resulted
from Eugene Island 339 and East Cameron 643 coming back on-line during July 2007. The decrease in crude oil and condensate volumes for the three months ended June 30, 2008 compared
to the three months ended June 30, 2007 resulted primarily from a three-day shut in at Eugene Island 339 for gas line repairs and a 12-day shut in at Ship Shoal 182/183 to repair a pipeline
obstruction during the three months ended June 30, 2008.

Capital
expenditures increased $70,321, or 29%, from $241,184 in the second quarter of 2007 to $311,505 in the second quarter of 2008. The higher capital expenses in the second quarter
of 2008 were primarily related to field workovers to help improve production performance. The capital expenditures for the second quarter of 2007 related primarily to damages caused by Hurricanes Rita
and Katrina. Reflected within the capital expenditures line item for 2008 are certain prior period capital expenditures from the working interest owners in the amount of ($495,600). The refund of
prior period capital expenditures resulted from the review procedures performed by an outside auditor as further described below.

The
Royalty Properties had undistributed net income of $27,704 as of June 30, 2008.

In
the second quarter of 2008, there was a net release of funds from the Special Cost Escrow account. The Trust's share of the funds released was $41,817. As of June 30, 2008,
$5,353,559 remained in the Special Cost Escrow account. The Special Cost Escrow is set aside for estimated abandonment costs and future capital expenditures, as provided for in the Conveyance. For
additional information relating to the Special Cost Escrow, see "Special Cost Escrow Account", below.

In
the second quarter of 2007, there was a net release of funds into the Special Cost Escrow account. The Trust's share of the net funds released was $300,403.

Six Months Ended June 30, 2008 and 2007

There were distributions of $7,088,418 or $1.491824 per Unit to the Unit holders for the six months ended June 30, 2008 as
compared to distributions of $3,221,507 or $0.677997 per Unit to the Unit holders for the same period in 2007.

Crude
oil and condensate revenues increased $4,479,910, or 26%, to $22,043,085 in the first six months of 2008 as compared to $17,563,175 for the same period in 2007, due to a 57%
increase in the average price of crude oil and condensate from $59.34 per barrel in the first six months of 2007 to $93.18 per barrel in the first six months of 2008. The increase was partially offset
by a 20% decrease in crude oil and condensate volume to 236,562 barrels in the first six months of 2008 from 295,989 barrels in the first six months of 2007.

Gas
revenues increased $1,503,820, or 31%, to $6,307,826 in the first six months of 2008 from $4,804,006 for the same period in 2007, due to an increase in gas volumes of 22% to 807,263
Mcf in the first six months of 2008 from 661,059 Mcf for the same period in 2007 in addition to a 7% increase in the average price received for natural gas to $7.81 per Mcf in the first six months of
2008 from $7.27 per Mcf in the same period of 2007. Gas products revenue increased $1,489,670, or 502%, to

10

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$1,786,187
in the first six months of 2008 from $296,517 in the same period of 2007, primarily due to an increase in production volume of 1,007,840 gallons, or 295%, to 1,349,521 gallons in the first
six months of 2008 from 341,681 gallons in the same period of 2007.

The
decrease in crude oil and condensate volumes for the first six months of 2008 were offset by higher prices during this period compared to the first six months of 2007. Increases in
gas volumes and gas products production volumes resulted from Eugene Island 339 and East Cameron 643 coming back on-line during July 2007 after hurricane damages were repaired.

The
Trust's share of capital expenditures decreased $1,288,896, from $1,174,724 in the first six months of 2007 to ($114,172) in the same period of 2008. The higher amount of capital
expenditures for the first six months of 2007 related primarily to damages caused by Hurricanes Rita and Katrina. The negative capital expenditures number for the first six months of 2008 resulted
from an adjustment to capital expenditures based on an outside audit discussed below under "Operational Review".

The
Royalty Proprieties had undistributed net income of $88,115 as of June 30, 2008.

In
the first six months of 2008, there was a net release of funds into the Special Cost Escrow account. The Trust's share of the net funds released was $1,360,005. In the first six
months of 2007, there was a net deposit of funds into the Special Cost Escrow account. The Trust's share of the net funds deposited was $504,778. As of June 30, 2008, $5,353,559 remained in the
Special Cost Escrow account. The Special Cost Escrow is set aside for estimated abandonment costs and future capital expenditures, as provided for in the Conveyance. For additional information
relating to the Special Cost Escrow, see "Special Cost Escrow Account", below.

Reserve for Future Trust Expenses

In accordance with the provisions of the Trust Agreement, generally all Royalty income received by the Trust, net of Trust general and
administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. The Trust has previously
determined that a cash reserve equal to approximately three times the average expenses of the Trust during each of the past three years was sufficient to provide for future administrative expenses in
connection with the winding up of the Trust. During the second quarter of 2008, the Trust decreased its reserve by $109,269 for a reserve balance of $2,136,178 as of June 30, 2008. The reserve
amount at December 31, 2007 was $1,883,726.

Other

The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of oil and gas
produced from the Royalty Properties as well as capital expenditures by the Working Interest Owners that may or may not be included in the Special Cost Escrow account. It should be noted that
substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major
petroleum producing nations, as well as the regional supply and demand for oil and gas, weather, industrial growth, conservation measures, competition and other variables.

11

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Operational Review

At the end of October 2005, approximately half of Chevron oil-equivalent production in the Gulf of Mexico remained shut in
due to damages from hurricanes in the third quarter. During 2006, several of the platforms and facilities on the Royalty Properties were restored, and by the third quarter of 2007 all but one of the
platforms and facilities had been restored. One of the platforms and facilities on Eugene Island was destroyed and has not been restored; efforts to establish a new platform are still in process. The
Working Interest Owner has also advised the Trust that the Working Interest Owner has completed the project to compress and re-inject gas to the B-5 well, which allows the
operator to increase oil production and to limit flaring of gas. Eugene Island 339 oil production increased during the second half of 2006 and the first quarter of 2007 as the B-5 well gas
injection project was completed. On Ship Shoal 182/183, gas production and sales resumed in July 2006 and full production resumed in the fourth quarter of 2006. On West Cameron 643, production was
shut in from September 2005 following Hurricane Rita's major damage to various platforms, but limited gas production resumed in late July 2006 before the wells loaded up and additional repairs were
required thus requiring the well to be shut in again during the second quarter 2006. Production at West Cameron 643 resumed May 2007.

The
Trust has engaged an outside auditor for the purpose of reviewing the books and records of certain Working Interest Owners with respect to the Royalty Properties and the related
payments to the Trust. Based on the initial report of this auditor, the Trustees believe that certain errors have occurred and are involved in ongoing discussions with such Working Interest Owners to
resolve these items. As part of this process, certain adjustments resulted in an additional cash distribution to the Trust during the first quarter of 2008. These amounts are comprised of a
one-time increase of approximately $31,716 in gas revenues, a one-time increase of approximately $43,287 in oil revenues, and a one-time credit of approximately
$123,900 in capital expenditures. An additional $127,973 from the outside audit was included in the second quarter 2008 distibution related to the outside audit. No assurance can be provided as to the
ultimate outcome of the remaining items under discussion.

Three Months Ended June 30, 2008 and 2007

The following operational information has been based on information provided to the Corporate Trustee by Chevron as the Managing
General Partner of the Partnership and by the applicable Working Interest Owners. The Trustees have no control over these operations or internal controls relating to this information.

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

Ship Shoal 182/183 crude oil revenues increased from $3,738,186 in the second quarter of 2007 to $5,197,061 in the second quarter of 2008, primarily due to an
increase in the average crude oil price from $59.19 per barrel in the second quarter of 2007 to $99.09 per barrel for the same period in 2008. The increase was partially offset by a decrease in net
crude oil production from 63,161 barrels in the second quarter of 2007 to 52,448 barrels in the second quarter of 2008. Gas revenues decreased from $2,251,252 in the second quarter of 2007 to $941,566
in the second quarter of 2008 due to a shut in resulting from an obstruction in the pipeline that caused a decrease in gas production to 101,823 Mcf in the second quarter 2008 compared to production
of 284,259 Mcf in the second quarter of 2007. The average gas sales price during the second quarter of 2008 was $9.25 per Mcf compared to $7.92 during

12

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the
second quarter of 2007. Capital expenditures decreased from $107,114 in the second quarter of 2007 to $1,727 in the second quarter of 2008 primarily due to the completion of the repair and upgrade
work on the platforms associated with damages caused by Hurricanes Rita and Katrina. Operating expenses increased from $861,367 in the second quarter of 2007 to $945,438 for the same period in 2008
due to rig workover expense.

Eugene
Island 339 net crude oil revenues increased from $3,989,800 in the second quarter of 2007 to $4,755,226 for the same period in 2008 due to an increase in the average crude oil
price from $56.60 per barrel in the second quarter of 2007 to $96.82 per barrel in the second quarter of 2008. The increase in price was partially offset by a decrease in volumes from 70,494 barrels
in the second quarter of 2007 to 49,114 barrels in the second quarter of 2008 due to a 3-day shut in for repairs. Gas revenues were $0 in the second quarter of 2007 due to damages caused
by Hurricanes Rita and Katrina, and $1,469,332 in the second quarter of 2008. Capital expenditures increased from $74,636 in the second quarter of 2007 to $284,321 in the second quarter of 2008
primarily due to repairs associated with the conversion to a water injector. Operating expenses increased from $297,167 in the second quarter of 2007 to $1,070,845 in the second quarter of 2008 due to
increased production and a rig workover.

West
Cameron 643 gas revenues were $0 in the second quarter of 2007 and $624,351 in the second quarter of 2008. Gas production was 0 Mcf in the second quarter of 2007, due to
damages caused by Hurricanes Rita and Katrina and a temporary field shut in, and 79,244 Mcf in the second quarter of 2008. Operating expenses decreased from $302,985 in the second quarter of 2007 to
$181,924 for the same period in 2008 due to platform and facility repairs in 2007, and capital expenditures remained flat from $0 in the second quarter of 2007 to $0 for the same period in 2008.

East
Cameron 371 crude oil revenues were $0 in the second quarter of 2007 and $346 in the second quarter of 2008 due to the field being shut in during 2007. Gas revenues were $0 for the
second quarter of 2007 and $4,659 for the second quarter of 2008 also due to the temporary shut in of the
field, as reported by Energy Resources Technology. Capital expenditures were $0 for the second quarter 2007 and 2008. Operating expenses decreased from $14,524 in the second quarter of 2007 to $12,792
for the same period in 2008.

Six Months Ended June 30, 2008 and 2007

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

Ship Shoal 182/183 crude oil revenues increased from $8,677,306 in the first six months of 2007 to $11,367,638 in the same period in 2008, primarily due to an
increase in the average crude oil price from $62.02 per barrel in the first six months of 2007 to $94.60 per barrel for the same period in 2008. The increase was partially offset by a decrease in net
crude oil production from 139,922 barrels in the first six months of 2007 to 120,163 in the same period of 2008. Gas revenues decreased from $4,484,899 in the first six months of 2007 to $2,614,285 in
the same period of 2008. Gas production decreased from 604,835 Mcf in the first six months of 2007 to 336,697 Mcf in the same period of 2008 due to a shut in as a result of an obstructed pipeline and
the natural decline of production. The natural gas sales price was $7.42 per Mcf in the first six months of 2007 compared to $7.76 per Mcf in the first six months of 2008. Capital expenditures
decreased from $578,023 in the first six months of 2007 to ($466,499) in the same period of 2008 primarily due to an audit adjustment for prior periods.

13

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Operating
expenses decreased from $1,851,959 in the first six months of 2007 to $1,511,393 for the same period in 2008 due to a decrease in production.

Eugene
Island 339 net crude oil revenues increased from $8,606,245 in the first six months of 2007 to $10,282,800 for the same period in 2008, due to an increase in the average crude oil
prices increased from $56.88 per barrel in the first six months of 2007 to $92.16 per barrel for the same period in 2008. The increase was partially offset by a decrease in volumes from 151,305
barrels in the first six months of 2007 to 111,572 barrels in the first six months of 2008 due to a 3-day field shut in for repairs. Gas revenues increased from $0 in the first six months
2007 to $2,461,106 for the same period in 2008, due to an increase in natural gas volumes from 0 Mcf in the first six months of 2007 to 316,092 Mcf for the same period in 2008. The increase is a
result of production coming back online after the completion of the new sales point. Capital expenditures increased from $129,741 in the first six months of 2007 to $290,380 in the same period in 2008
due to the conversion to a water injector.
Operating expenses increased from $887,768 in the first six months of 2007 to $1,463,934 in the same period in 2008 due to increased production.

West
Cameron 643 gas revenues increased from $219,217 in the first six months of 2007 to $921,625 for the period in 2008. This is due to an increase in gas volumes from 42,094 Mcf in the
first six months of 2007 to 121,432 Mcf for the same period in 2008. Operating expenses decreased from $525,420 for the first six months of 2007 to $348,423 for the same period in 2008, and capital
expenditures were $0 for the first six months of 2007 and 2008.

East
Cameron 371 crude oil revenues were $0 for the first six months of 2007 and $48,087 for the second six months of 2008 as a result of production coming back online from 0 barrels in
the first six months of 2007 to 531 barrels for the same period in 2008. Gas revenues increased from $14,724 for the first six months of 2007 to $252,605 for the same period in 2008. This is due to an
increase in gas volumes from 2,298 Mcf in the first six months of 2007 to 32,412 Mcf for the same period in 2008. Capital expenditures were $0 in the first six months of 2007 and 2008. Operating
expenses increased from $26,830 in the first six months of 2007 to $292,982 for the same period in 2008.

Liquidity and Capital Resources

Chevron has informed the Trustee that Chevron had budgeted approximately $14.7 million, net to the Trust's interest, in capital
expenditures during 2008 associated with Eugene Island 339 relating to side track drilling resulting from existing casing damage and a related delineation drilling project. Chevron has recently
informed the Trustee that the start date for the side track drilling project is now in September 2008, with completion thereof expected in October 2008. The start date for the delineation project is
now November 2008, with completion thereof expected in December 2008.

Future Net Revenues and Termination of the Trust

Based on a reserve study provided to the Trust by DeGolyer and MacNaughton, independent petroleum engineers, as of October 31,
2007 future net revenues attributable to the Trust's royalty interests were estimated at $54.8 million. Estimates of proved oil and gas reserves attributable to the Partnership's royalty
interest are based on existing economic and operating conditions in effect at October 31, 2007 in order to correspond with distributions to the Trust. Such reserve study also indicates that
approximately 76% of the future net revenues from the Royalty Properties are expected to be received by the Trust during the next three years. Upon termination of the Trust, the Trustees will

14

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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. Future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. In addition, because the Trust will terminate in the
event estimated future net revenues fall below $2.0 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. The discussion set forth above is qualified in its entirety by reference to the Trust's Annual Report on Form 10-K for the year ended December 31, 2007. The
Trust's Form 10-K is available at the website of the Securities and Exchange Commission ("SEC") atwww.sec.govor upon request from
the Corporate Trustee.

Special Cost Escrow Account

The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling
platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in
the Conveyance, the amount of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net
revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in
short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account
serves to reduce the Trust's share of allocated production costs.

Special
Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been paid
are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125%
of 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 will also be released when the balance in such account exceeds 125% of estimated future Special Costs. In the first six months of 2008, there was a net release of funds to
the Special Cost Escrow account of $1,360,005. In the first six months of 2007, there was a net deposit of funds to the Special Cost Escrow account of $504,778.

As
of June 30, 2008, $5,353,559 remained in the Special Cost Escrow account.

Chevron,
in its capacity as the Managing General Partner of the Partnership, 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.

15

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Overview of Production, Prices and Royalty Income

The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas
recorded by the Working Interest Owners
for the Royalty Properties, as well as the Working Interest Owners' calculations of the Net Proceeds and the royalties paid to the Trust during the periods indicated. Net Proceeds due to the Trust are
calculated for each three-month period commencing on the first day of February, May, August and November.

Royalty Properties
Three Months Ended
June 30,(1)2008

2007Crude oil and condensate (bbls)


103,147


135,984Natural gas and gas products (Mcfe)


423,667


310,833Crude oil and condensate average price, per bbl

$
97.73

$
57.83Natural gas average price, per Mcf (excluding gas products)

$
8.70

$
7.91Crude oil and condensate revenues

$
10,080,263

$
7,863,691Natural gas and gas products revenues


3,693,401


2,427,749Production expenses


(2,773,442
)

(1,876,584
)Capital expenditures


(311,505
)

(241,184
)Undistributed net incomecollection of (increase in)(2)


27,704


Refund of (provision for) Special Cost Escrow


288,640


1,489,376Net Proceeds

$
11,005,061

$
9,663,048Royalty interest


x25
%

x25
%Partnership share

$
2,751,265

$
2,415,762Trust interest


x99.99
%

x99.99
%Trust share of Royalty Income

$
2,750,990

$
2,415,521


---

16

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Royalty Properties
Six Months Ended
June 30,2008

2007Crude oil and condensate (bbls)


236,562


295,989Natural gas and gas products (Mcfe)


1,000,051


709,870Crude oil and condensate average price, per bbl

$
93.18

$
59.34Natural gas average price, per Mcf (excluding gas products)

$
7.81

$
7.27Crude oil and condensate revenues

$
22,043,085

$
17,563,175Natural gas and gas products revenues


8,094,013


5,100,523Production expenses


(4,736,015
)

(4,171,949Capital expenditures


114,172


(1,174,724
)Undistributed net incomecollection of (increase in)(1)


(88,115
)

(2,092
)Refund of (provision for) Special Cost Escrow


5,850,032


(1,584,540
)Net Proceeds

$
31,277,172

$
15,730,393Royalty interest


x25
%

x25
%Partnership share

$
7,819,293

$
3,932,598Trust interest


x99.99
%

x99.99
%Trust share of Royalty Income

$
7,818,511

$
3,932,205


---

Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

No material changes have occurred since our Annual Report on Form 10-K for the year-ended
December 31, 2007. Reference is also made to Note 2 of the Notes to Financial Statements included in Item 1 of this Form 10-Q.

Item 4T.    Controls and Procedures.

Evaluation of disclosure controls and procedures.The Corporate Trustee maintains disclosure controls and procedures designed to ensure that information required
to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is
accumulated and communicated by Chevron, as the Managing General Partner of the Partnership, and the Working Interest Owners to The Bank of New York Trust Company, N.A., as Corporate Trustee of the
Trust, and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

17

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As
of the end of the period covered by this report, the Corporate Trustee carried out an evaluation of the Trust's disclosure controls and procedures. Mike Ulrich, as Trust Officer of
the Corporate Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

Due
to the contractual arrangements of (i) the Trust Agreement, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding
information furnished by the Working Interest Owners, the Trustees rely on (A) information provided by the Working Interest Owners, including historical operating data, plans for future
operating and capital expenditures, reserve
information and information relating to projected production, (B) information from the Managing General Partner of the Partnership, including information that is collected from the Working
Interest Owners, and (C) conclusions and reports regarding reserves by the Trust's independent reserve engineers. See Part I, Item 1A. "Risk FactorsThe Trustees and
the Unit holders have no control the over the operation or development of the Royalty Properties and have litte influence over operation or development" and "The Trustees rely upon on the
working interest owners and managing general partner for information regarding the Royalty Properties" in the Trust's Annual Report on Form 10-K for the year ended
December 31, 2007, and "Note 5Negative Adjustments" of the financial statements and "Management's Discussion and Analysis of Financial Condition and Results of Operations"
relating to operating information on East Cameron 371 included in the Annual Report on Form 10-K for the year ended December 31, 2007 for a description of certain risks
relating to these arrangements and reliance and applicable adjustments to operating information when reported by the Working Interest Owners to the Corporate Trustee and recorded in the Trust's
results of operations.

Changes in Internal Control Over Financial Reporting.During the three months ended June 30, 2008, there has been no change in the Corporate Trustee's
internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Corporate Trustee's internal control over financial reporting relating to the
Trust. The Corporate Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of the Working Interest
Owners or the Managing General Partner of the Partnership.

PART IIOTHER INFORMATION

Item 1A.    Risk Factors.

There have not been any material changes from risk factors previously disclosed in the Trust's response to Item 1A of
Part 1 of the Trust's Annual Report on Form 10-K for the year ended December 31, 2007.

18

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PART IIOTHER INFORMATION

Item 6.    Exhibits.

(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference.)

SEC File or Registration Number

Exhibit Number4
(a)*


Trust Agreement dated as of January 1, 1983, among Tenneco Offshore Company, Inc., Texas Commerce Bank National Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as
individual trustees (Exhibit 4(a) to Form 10-K for the year ended December 31, 1992 of TEL Offshore Trust)


0-6910


4
(a)4
(b)*


Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended December 31,
1992 of TEL Offshore Trust)


0-6910


4
(b)4
(c)*


Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)


0-6910


4
(c)4
(d)*


Amendments to TEL Offshore Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)


0-6910


4
(d)4
(e)*


Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for the 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)31



Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 200232



Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


19

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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 TRUSTBy:

The Bank of New York Trust Company, N.A.,
Corporate TrusteeBy:

/s/MIKE ULRICH Mike UlrichVice PresidentDate: August 14, 2008


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

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