UNITED STATES
SECURITIES 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 1934 for the quarterly period ended June 30, 2010Oro

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


Commission File Number: 0-06910



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 Mellon Trust Company, N.A.
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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit and post such files). Yes o    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

As of August 12, 2010, 4,751,510 Units of Beneficial Interest in TEL Offshore Trust were outstanding.



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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 Chevron USA, Inc., the Managing General Partner of the TEL Offshore Trust Partnership, has advised the Trust that the Managing General Partner believes
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, 2009 under Part I, Item 1A "Risk Factors" and in Part II, Item 1A of this Form 10-Q.
All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements.

i

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PART IFINANCIAL INFORMATION

Item 1.    Financial Statements.

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

June 30,
2010

December 31,
2009AssetsCash and cash equivalents

$
810,935

$
1,263,080Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,243,044 and $28,240,469, respectively


24,611


27,186Total assets

$
835,546

$
1,290,266Liabilities and Trust CorpusDistribution payable to Unit holders

$


$
Reserve for future Trust expenses


810,935


1,263,080Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)


24,611


27,186Total liabilities and Trust corpus

$
835,546

$
1,290,266


STATEMENTS OF DISTRIBUTABLE INCOME        (Unaudited)

Three Months Ended
June 30,

Six Months Ended
June 30,2010

2009

2010

2009Royalty income

$


$


$


$
Interest income


27


379


148


95527


379


148


955(Increase) decrease in reserve for future Trust expenses


267,791


210,775


452,145


541,791General and administrative expenses


(267,818
)

(211,154
)

(452,293
)

(542,746
)Distributable income

$


$


$


$
Distributions per Unit (4,751,510 Units)

$
.000000

$
.000000

$
.000000

$
.000000


1

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STATEMENTS OF CHANGES IN TRUST CORPUS        (Unaudited)

Three Months Ended
June 30,

Six Months Ended
June 30,2010

2009

2010

2009Trust corpus, beginning of period

$
25,563

$
30,636

$
27,186

$
31,338Distributable income











Distribution payable to Unit holders











Amortization of net overriding royalty interest


(952
)

(667
)

(2,575
)

(1,369
)Trust corpus, end of period

$
24,611

$
29,969

$
24,611

$
29,969


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 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. 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
January 14, 1983, Tenneco Offshore distributed Units to holders of Tenneco Offshore's common stock on the basis of one Unit for each common share owned on such date.

The
terms of the Trust Agreement, dated January 1, 1983, provide, among other things, that:



3

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1Trust Organization (Continued)

The
Trust is currently administered by The Bank of New York Mellon Trust Company, N.A. (the "Corporate Trustee"), 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 Gary C. Evans and Jeffrey S. Swanson (the "Individual Trustees"), as trustees (the "Trustees"). An Individual Trustee was removed as a Trustee of the Trust in June 2010, and a
successor for such Trustee has not yet been appointed.

Note 2Basis of Accounting

The accompanying unaudited financial information has been prepared by the Corporate Trustee. 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 that 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, 2009.

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, which is
calculated on a

4

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2Basis of Accounting (Continued)

units-of-production
basis, is charged directly to Trust corpus since such amount does not affect distributable income.

On
the last business day of each calendar quarter, the Working Interest Owners pay to the Partnership 25% of the Net Proceeds (as defined below in Note 3) for the immediately
preceding Quarterly Period. A Quarterly Period is each period of three months commencing on the first day of February, May, August and November. In turn, the Partnership distributes funds to its
partners on the last business day of each calendar quarter. Cash distributions from the Trust are made in January, April, July and October of each year, and are payable to Unit holders of record as of
the last business day of each calendar quarter. Thus, any cash conveyed to the Trust from the Royalty during the quarter ended June 30, 2009 would substantially represent the revenues and
expenses from the Royalty Properties from February 2009 through April 2009. Similarly, any cash conveyed to the Trust from the Royalty during the quarter ended June 30, 2010 would substantially
represent the revenues and expenses from the Royalty Properties from February 2010 through April 2010. However, there was no cash conveyed to the Trust from the Royalty Properties from either February
2009 through April 2009 or February 2010 through April 2010. The financial and operating information included in this Form 10-Q for the three months ended June 30, 2010 and
June 30, 2009 represents financial and operating information with respect to the Royalty Properties for the immediately preceding months of February, March and April. Similarly, financial and
operating information with respect to the Royalty Properties for the six months ended June 30, 2010 and June 30, 2009 represents financial and operating information with respect to the
Royalty Properties for the immediately preceding months of November through April. Income from the Royalty is recorded by the Trust on a cash basis, when it is received by the Trust from the
Partnership.

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 include 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 may be recognized to write down the asset to the lower of its estimated fair value
or net book 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.

5

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2Basis of Accounting (Continued)

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. 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 the 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, economic conditions
generally and other variables. The Trust does not enter into any hedging transactions on future production.

The
Corporate Trustee has evaluated subsequent events through the date that these financial statements were issued.

Going Concern Uncertainty

The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. The lack of Net
Proceeds and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going concern (see Notes 4 and 6). Certain potential
alternatives available to the Trustees are described in Note 6. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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,

6

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 3Net Overriding Royalty Interest (Continued)

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.

Set
forth below are the quarterly distributions made by the Trust for 2010 and 2009.

Quarter

Distribution2010:Second

$
0First


02009:Fourth

$
0Third


0Second


0First


0


Production
ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. On March 25, 2009, the Trust announced there
would be no distribution for the first quarter of 2009. Similarly, on June 26, 2009, September 25, 2009, December 23, 2009, March 23, 2010 and June 23, 2010, the
Trust announced there would be no trust distributions for the second, third and fourth quarters of 2009 or the first and second quarters of 2010, respectively.

There
are not likely to be sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable
future. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue to be severely impacted by reduced production, from historical levels, and the amount of expenditures incurred
that are associated with such damages, including the expenditures required to plug and abandon the wells on Eugene Island 339, and, as currently expected, to redevelop the facility at Eugene Island
339. Future Net

7

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4Distributions to Unit Holders (Continued)

Proceeds
from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the operators of the Royalty
Properties. The Trust's net portion of the aggregate cost to plug and abandon the wells subject to the royalty on Eugene Island 339 is estimated to be approximately $13 million, approximately
$8.1 million of which had been incurred through June 30, 2010. If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust
will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest. As a result of the damage inflicted by Hurricane Ike, the Trust has not
received Net Proceeds since December 2008. For the second quarter of 2010, under the terms of the Conveyance, gross proceeds for the Royalty Properties exceeded related development and production
costs, with the Trust's portion of such excess equal to approximately $265,000. However, as of June 30, 2010, aggregate development and production costs for the Royalty Properties since
November 2008 have exceeded the related proceeds of production from the Royalty Properties by approximately $5.9 million. Significant development and production costs will continue to be
incurred as Eugene Island 339 is redeveloped. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this
time, the ultimate outcome of these matters cannot be determined with any degree of certainty.

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

8

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 5Special Cost Escrow Account (Continued)

released
when the balance in such account exceeds 125% of estimated future Special Costs. In the second quarter of 2010, there were no funds released or escrowed from the Special Cost Escrow account.
As of June 30, 2010, $4,306,383 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
USA, Inc. ("Chevron"), in its capacity as 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 generally maintains a cash reserve, equal to approximately three times the average annual expenses of the Trust during each of the then past three years, to provide for future
administrative expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the
Trust has not received sufficient Net Proceeds to maintain the reserve at such level. During the second quarter of 2010, the Trust used $267,791 from the reserve account for current expenses, leaving
a reserve balance as of June 30, 2010 of $810,935, or approximately one times the average annual expenses of the Trust during the three-year period ended June 30, 2010. The
reserve amount at December 31, 2009 was $1,263,080, or approximately 1.7 times the average annual expenses of the Trust during the three-year period ended December 31, 2009.

There
are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. Absent the receipt of Net Proceeds or other actions being taken, at some point,
the Trust will not have sufficient funds to pay the liabilities of the Trust. While the ultimate outcome cannot be determined at this time, the Trust will likely not receive a distribution of Net
Proceeds prior to depleting its reserves for payment of obligations of the Trust. As such, the Trustees may take certain actions, discussed below, permitted under the Trust Agreement, which could
materially impact the Unit holders.

Pursuant
to the terms of the Trust Agreement, the Trustees are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that
cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no further distributions will be made to the Unit
holders until the indebtedness created by such borrowings has been paid in full. However, there can be no assurance as to the terms and conditions of any such financing, or that any such financing can
actually be obtained.

9

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 6Reserve For Future Trust Expenses (Continued)

The
Trust Agreement further provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders
(a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise
their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

***********

10

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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

In May 2007, the Trust engaged an independent oil and gas accounting firm 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. As part of this audit review process, certain adjustments to revenues, production volumes, prices
and expenditures have occurred, and references below to a prior period audit adjustment, or an audit of prior periods, refers to the audit described in this paragraph. See "Operational
Review". The adjustments resulting from such audit review were completed in the second quarter of 2009.

In
January 2010, the Trust engaged the same independent oil and gas accounting firm to review the books and records of certain Working Interest Owners with respect to the Royalty
Properties and the related payments to the Trust. Such audit review process is currently on-going and may result in certain adjustments to revenues, production volumes, prices and
expenditures. No assurance can be provided as to the ultimate outcome of such audit review process.

Three Months Ended June 30, 2010 and 2009

There were no distributions to the Unit holders for the three months ended June 30, 2010 and 2009.

11

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Crude
oil and condensate revenues increased $494,266, or 27%, to $2,307,559 in the second quarter of 2010 from $1,813,293 in the second quarter of 2009, due to increased realized prices.
Oil volumes during the second quarter of 2010 decreased 16% to 29,867 barrels, compared to 35,475 barrels of oil produced in the second quarter of 2009, due primarily to a 36-day field
shut-in at Ship Shoal 182/183 related to pipeline repairs. The revenues for the second quarter of 2009 reflect a credit of $186,806 associated with an audit for prior periods. The average
price received for crude oil and condensate increased 52%, or $26.15, to $77.26 per barrel in the second quarter of 2010 from $51.11 per barrel in the second quarter of 2009 (after taking into account
a minor prior period pricing adjustment in 2009).

Gas
revenues increased $340,837, or 3,917%, to $349,538 in the second quarter of 2010 from $8,701 in the second quarter of 2009, due primarily to increased production at Ship Shoal
182/183. Gas volumes during the second quarter of 2010 increased 4,089% to 57,971 Mcf, compared to 1,384 Mcf produced in the second quarter of 2009. The revenues and volumes for the second quarter of
2009 reflect debits to correct an error in revenue allocation in August 2008 for $4,603 in revenues and 1,234 Mcf of gas. The average price received for natural gas was $6.03 per Mcf in the second
quarter of 2010 compared to $6.29 per Mcf in the second quarter of 2009. Prior to taking into account such adjustments to revenues and volumes, the average price received for natural gas would have
been $5.08 per Mcf in the second quarter of 2009. Gas products revenue increased $23,661, or 182%, to $36,721 in the second quarter of 2010 from $13,060 in the second quarter of 2009. Gas products
volumes during the second quarter of 2010 increased 868% to 28,261 gallons, compared to 2,920 gallons in the second quarter of 2009.

Capital
expenditures increased by $58,213, or 531%, from $10,964 in the second quarter of 2009 to $69,177 in the second quarter of 2010. The higher amount of capital expenditures during
the second quarter of 2010 related primarily to re-zoning and facility work at Ship Shoal 182/183 and well workovers at South Timbalier 36/37.

Operating
expenses decreased by $9,192,307, or 85%, from $10,763,900 in the second quarter of 2009 to $1,571,593 in the second quarter of 2010, due primarily to less well and platform
abandonment work being conducted at Eugene Island 339 in the second quarter of 2010 as compared to the second quarter of 2009.

The
Royalty Properties had undistributed net income of $1,045,972 in the second quarter of 2010.

In
the second quarter of 2010, there were no funds released or escrowed from the Special Cost Escrow account. As of June 30, 2010, $4,306,383 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. The Special Cost Escrow account 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 account, see "Special Cost Escrow Account" below.

In
the second quarter of 2009, there were no funds released or escrowed from the Special Cost Escrow account. As of June 30, 2009, $4,306,735 remained in the Special Cost Escrow
account.

Six Months Ended June 30, 2010 and 2009

There were no distributions to the Unit holders for the six months ended June 30, 2010 and 2009.

12

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Crude
oil and condensate revenues increased $3,332,903, or 118%, to $6,155,478 in the first six months of 2010 as compared to $2,822,575 for the same period in 2009, due primarily to
increased production at Ship Shoal 182/183 and increased realized prices. Oil volumes increased 50% to 80,775 barrels in the first six months of 2010 from 53,985 barrels in the first six months of
2009. The revenues and volumes for the first six months of 2009 reflect credits associated with an audit for prior periods for $224,511 in
revenues and 311 barrels. The average price received for crude oil and condensate increased 46%, or $23.93, to $76.21 per barrel in the first six months of 2010 from $52.28 per barrel in the first six
months of 2009. Prior to taking into account such adjustments to revenues and volumes, the average price received for crude oil and condensate would have been $48.40 per barrel in the first six months
of 2009.

Gas
revenues decreased $25,693, or 3%, to $810,669 in the first six months of 2010 from $836,362 for the same period in 2009. Gas volumes increased 19% to 156,821 Mcf in the first six
months of 2010 from 132,370 Mcf for the same period in 2009. The revenues and volumes for the first six months of 2009 reflect net credits of $808,484 in revenues and 127,711 Mcf of gas for prior
adjustments. The average price received for natural gas decreased 19%, or $1.15, to $5.17 per Mcf in the first six months of 2010 from $6.32 per Mcf in the same period of 2009. Prior to taking into
account such adjustments to revenues and volumes, the average price received for natural gas would have been $5.98 per Mcf in the first six months of 2009. Gas products revenue decreased $77,404, or
40%, to $118,222 in the first six months of 2010 from $195,626 in the same period of 2009, primarily due to an decrease in production volume of 80,764 gallons, or 47%, to 92,146 gallons in the first
six months of 2010 from 172,910 gallons in the same period of 2009.

Capital
expenditures decreased $191,395, or 67%, from $287,388 in the first six months of 2009 to $95,993 in the same period of 2010. The higher amount of capital expenditures during the
first six months of 2009 related primarily to repairs of damages caused by Hurricane Ike in September 2008. Reflected in the capital expenditures for the first six months of 2009 is a refund of
$59,794 for certain prior period audit adjustments.

Operating
expenses decreased by $9,114,556, or 54%, from $16,947,089 in the first six months of 2009 to $7,832,533 in the first six months of 2010, due primarily to less well and
platform abandonment work being conducted at Eugene Island 339 in the second quarter of 2010 as compared to the second quarter of 2009. Reflected in the operating expenses for the first six months of
2009 are cost allocation refunds of an aggregate of $115,252 for certain prior period adjustments. Reflected within the operating expenses are management fees to Chevron, as Managing General Partner
of the Partnership, of $607,249 and $437,703 for the first six months of 2009 and the first six months of 2010, respectively.

The
Royalty Properties had undistributed net loss of $11,712,953 for the six months ended June 30, 2010.

In
the first six months of 2010 and 2009, no funds were released or escrowed from the Special Cost Escrow account.

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

13

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annual
expenses of the Trust during each of the then past three years was sufficient to provide for future administrative expenses in connection with the winding up of the Trust. However, as a result
of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the Trust has not received sufficient Net Proceeds to maintain the reserve at such level. During the
second quarter of 2010, the Trust used $267,791 from the reserve for current expenses, leaving a reserve balance as of June 30, 2010 of $810,935, or approximately one times the average annual
expenses of the Trust during the three-year period ended June 30, 2010. The reserve amount at December 31, 2009 was $1,263,080, or approximately 1.7 times the average annual
expenses of the Trust during the three-year period ended December 31, 2009. See "Liquidity and Capital Resources" for a discussion of certain potential alternatives
available to the Trustees for obtaining cash for Trust expenses.

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 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, economic conditions generally and other variables.

Operational Review

The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike in September 2008. Crude oil revenues from
Eugene Island 339 represented approximately 48% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 47% of such revenues for the nine months ended
September 30, 2008. Eugene Island 339 contributed approximately 12% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 41% of such revenues for the
nine months ended September 30, 2008. Based on a prior year reserve study prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants, Eugene Island 339 accounted for
approximately 34% of the total future net revenues attributable to the Partnership's interest in the royalty as of October 31, 2007. Chevron is working on the plugging and abandonment of the
existing wells, clearing debris and otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the second quarter of 2012. The Trust's net portion of
the aggregate cost to plug and abandon the wells subject to the royalty on Eugene Island 339 is estimated to be approximately $13 million, approximately $8.1 million of which had been
incurred through June 30, 2010. Generally, if production ceases from an outer continental shelf lease, like that for Eugene Island 339, production must be restored or drilling operations must
commence within 180 days of the cessation of production (which was in early March 2009 with respect to Eugene Island 339 given the cessation of production in September 2008 resulting from
Hurricane Ike), or the lease will be terminated. Alternatively, an operator of a lease may seek a Suspension of Operations, or "SOP," that, if approved by the regional supervisor of the Bureau of
Ocean Energy Management, Regulation and Enforcement ("BOEM," formerly the Minerals Management Service), allows additional time to restore production in the event of certain circumstances, such as
hurricanes and other events beyond the control of the operator. Chevron, as the operator of Eugene Island 339, sought and obtained an SOP that provides for the redevelopment of Eugene Island 339 and
the

14

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adjacent
lease, Eugene Island 338 (which is not a Royalty Property), as a single development project. The SOP extends the lease on Eugene Island 339 until November 30, 2010, as long as certain
milestones are met. Such milestones include the awarding of a front-engineering contract, which was completed in February 2010, the completion of front-end engineering and design work,
which was completed in July 2010, and the awarding of contracts for the fabrication of the platform, substructure, and equipment by November 30, 2010. Chevron is required to provide the BOEM
with periodic updates on Chevron's progress on such redevelopment. Although the existing SOP expires on November 30, 2010, the BOEM has acknowledged that production will not be restored at
Eugene Island 339 until October 2012. Therefore, Chevron must submit, and obtain approval by the regional supervisor of the BOEM of, a new SOP prior to November 30, 2010 to proceed with the
redevelopment of Eugene Island 338 and 339. In December 2009, Chevron entered into an agreement with a third party to assist in the redevelopment of Eugene Island 338 and 339. The redevelopment plan
provided that three wells were to be drilled from a common open water location in Eugene Island 338 in the second quarter of 2010. The first well of the three-well drilling program
has been drilled. Drilling activity has
been suspended and the drilling rig moved off location pending the approval of drilling permits under the new guidelines issued by the BOEM on June 8, 2010 pursuant to Notice to Lessees
No. 2010-N05, "Increased Safety Measures for Energy Development on the OCS". The information derived from these wells is to be used, in part, to determine the size of the platform
and the required production processing equipment. If the three wells are successful and a platform is set, the plan is to drill wells into Eugene Island 339 and additional wells in Eugene
Island 338 from the proposed platform. If Chevron determines that it is warranted, and the redevelopment plans are successful, first production at Eugene Island 339 is anticipated in the fourth
quarter of 2012. Restoration of production at Eugene Island 338 and 339 is a complex process and cannot be assured at this time. If the initial three-well drilling program is not timely
and fully prosecuted or is not successful, Chevron intends to reevaluate the redevelopment of Eugene Island 338 and 339. The costs for such a redevelopment would be significant. While Chevron has
stated that it intends to redevelop Eugene Island 338 and 339, there is no obligation for Chevron to continue to pursue such redevelopment. Failure or inability to pursue such a redevelopment, and on
the timeframes approved by the BOEM, could result in a loss of the lease. At this time, there can be no assurance that production will be restored at Eugene Island 339. Additionally, the Trust cannot
predict at this time the impact, if any, that the recent oil spill in the U.S. Gulf of Mexico, related to the sinking of theDeepwater Horizondrilling
rig, may have on the operations of the Royalty Properties, particularly a redevelopment of Eugene Island 339. See "Risk Factors" under Item 1A of this Form 10-Q.

Production
at Ship Shoal 182/183 ceased following damage inflicted by Hurricane Ike in September 2008. While the hurricane caused limited surface damage to the facilities at Ship Shoal
182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. Crude oil revenues from Ship Shoal
182/183 represented approximately 50% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 51% of such revenues for the nine months ended September 30,
2008. Ship Shoal 182/183 contributed approximately 77% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 42% of such revenues for the nine months ended
September 30, 2008. A limited volume of oil production was restored in November 2008. The volume of oil production that can be produced is limited by the amount of gas that is also produced by
the oil wells. The third-party transporter's natural gas pipeline repairs were completed and gas sales at Ship Shoal 182/183 were restored on June 26, 2009. However, the pipeline was shut down
in mid-September for additional

15

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repairs.
Production sales for both oil and natural gas at Ship Shoal 182 and 183 were restored on October 8, 2009 following completion of such additional repairs. Oil and gas production at Ship
Shoal 182/183 ceased in March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Such oil pipeline has since been repaired and Ship Shoal 182/183 was reopened on May 1,
2010 after a 36-day shut-in.

In
addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. Chevron,
as the Managing General Partner of the Partnership, understands that, as a result of the cessation of production at West Cameron 643 due to the damages inflicted by Hurricane Ike to a third-party
transporter's pipeline, Hilcorp submitted to the BOEM a program to restore production at West Cameron 643 and that such request was granted. The approval by the BOEM expired by its terms on
May 31, 2010, and Chevron understands that Hilcorp submitted to the BOEM a request for an extension but that such request was denied. Chevron also understands that the plugging and abandonment
of the wells and related infrastructure at West Cameron 643 is expected to commence in late 2010 or early 2011, with a deadline to complete such activities of June 1, 2011. The field operator
for East Cameron 371 has reported to Chevron that a review of the remaining reserves for East Cameron 371 has been conducted, and that the wells at East Cameron 371 have been depleted. The lease for
East Cameron 371 expired on March 31, 2010 and the field operator has informed Chevron that field abandonment work, including the related wells, equipment platforms and any field
infrastructure, will commence within one year of such date.

In
May 2007, the Trust engaged an independent oil and gas accounting firm 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. As part of this audit review process, certain adjustments to revenues, production volumes, prices and capital expenditures have occurred, and
references below to a prior period audit adjustment, or an audit of prior periods, refers to the audit described in this paragraph. Such audit resulted in certain credits being made for the benefit of
the Trust in the first quarter of 2009, consisting of approximately $203,272 in gas revenues, approximately $9,426 in oil revenues, approximately $14,948 in capital expenditures and approximately
$9,248 in operating expenditures. All remaining audit adjustments were completed during the second quarter of 2009. The Trust's proportionate interest in the various audit adjustments for the second
quarter of 2009 included a one-time credit of $1,151 in gas revenues, an increase of $46,702 in crude oil revenues related to Eugene Island 354 and a one-time credit adjustment
of $19,625 in operating expenses.

Three Months Ended June 30, 2010 and 2009

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

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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 $1,564,170 in the second quarter of 2009 to $2,208,849 in the second quarter of 2010, due to an increase in the average crude oil
price received from $45.92 per barrel in the second quarter of 2009 to $77.30 per barrel for the same period in 2010. Net crude oil production decreased from 34,065 barrels in the second quarter of
2009 to 28,576 barrels in the second quarter of 2010. Gas revenues increased from $0 in the second quarter of 2009 to $331,535 in the second quarter of 2010. Gas production increased from 0 Mcf in the
second quarter of 2009 to 54,918 Mcf in the second quarter of 2010. The lack of gas production in the second quarter of 2009 was due to the cessation of production in September 2008 resulting from
damages inflicted by Hurricane Ike. Capital expenditures increased from $6,982 in the second quarter of 2009 to $53,450 in the second quarter of 2010 primarily due to re-zoning and
facility work. Operating expenses increased from $698,827 in the second quarter of 2009 to $846,547 for the same period in 2010 primarily due to continuing repair costs related to damages inflicted by
Hurricane Ike. Operating expenses for the second quarter of 2009 reflect a credit of $78,260 associated with an audit of a prior period.

Eugene
Island 339 net crude oil revenues and volumes were $0 for the second quarter of 2010 and 2009. Gas revenues and volumes were $0 in the second quarter of 2010 and 2009. Capital
expenditures decreased from $3,795 in the second quarter of 2009 to $(327) in the second quarter of 2010. Capital expenditures made during the second quarter of 2009 relate primarily to damages
inflicted by Hurricane Ike. Capital expenditures for the second quarter of 2010 reflect a credit of $327 associated with abandonment expense during a prior period. Operating expenses decreased from
$9,274,930 in the second quarter of 2009 to $541,428 in the second quarter of 2010, due primarily to less well and platform abandonment work being conducted in the second quarter of 2010 as compared
to the second quarter of 2009.

West
Cameron 643 gas revenues increased from $(4,603) in the second quarter of 2009 to $5,244 in the second quarter of 2010. Gas volumes increased from (1,234) Mcf in the second quarter
of 2009 to 0
Mcf for the same period in 2010. There was no actual gas production during the second quarter of 2009 and 2010 as a result of the field being shut-in following Hurricane Ike in September
2008. The negative revenues and volumes for the second quarter of 2009 are a result of an audit adjustment associated with prior periods. The positive revenues for the second quarter of 2010 are the
result of a correction to a prior period audit adjustment made in the first quarter of 2009. Operating expenses decreased from $417,432 in the second quarter of 2009 to $46,144 for the same period in
2010, due to the field being shut-in after Hurricane Ike in September 2008 as a result of damages to a third-party transporter's pipeline. Capital expenditures decreased from $231 in the
second quarter of 2009 to $0 for the same period in 2010.

East
Cameron 371 crude oil revenues were $0 in the second quarter of 2009 and 2010 as a result of the field being shut-in following Hurricane Ike in September 2008.
Production was 0 barrels in the second quarter of 2009 and 2010. Gas revenues were $0 in the second quarter of 2009 and 2010 as a result of no gas volumes in the second quarter 2009 and 2010.
Operating expenses were $0 in the second quarter of 2009 and 2010.

South
Timbalier 37/27 crude oil revenues increased from $62,297 in the second quarter of 2009 to $84,930 for the same period in 2010 due to an increase in realized oil prices. There was
a decrease in crude oil production volumes to 1,103 barrels in the second quarter of 2010 from 1,409 barrels in the

17

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second
quarter of 2009. The average crude oil price received increased from $44.22 per barrel in the second quarter of 2009 to $76.98 per barrel in the second quarter of 2010. Gas revenues increased
from $13,215 in the second quarter 2009 to $17,456 in the second quarter of 2010 due primarily to an increase in gas prices realized and an increase in gas production. There was an increase in natural
gas volumes from 2,604 Mcf in the second quarter of 2009 to 2,959 Mcf in the second quarter of 2010. The average natural gas price received increased from $5.08 per Mcf in the second quarter of 2009
to $5.90 per Mcf in the second quarter of 2010. Capital expenditures increased from $(45) in the second quarter of 2009 to $16,053 in the second quarter of 2010, due primarily to well workovers.
Capital expenditures for the second quarter of 2009 reflect a $45 credit primarily related to workover cost adjustments for wells at South Timbalier 37. Operating expenses decreased from $11,226 in
the second quarter of 2009 to $11,017 in the second quarter of 2010. Operating expenses for the second quarter of 2009 reflect a $220 credit related to a prior period audit adjustment.

Six Months Ended June 30, 2010 and 2009

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

Ship
Shoal 182/183 crude oil revenues increased from $2,473,541 in the first six months of 2009 to $5,967,751 in the same period in 2010, due to an increase in net crude oil production
from 51,189 barrels in the first six months of 2009 to 78,284 in the same period of 2010. There was a decrease in the average crude oil price from $94.60 per barrel in the first six months of 2009 to
$76.24 per barrel for the same period in 2010. Gas revenues increased from $725,720 in the first six months of 2009 to $788,004 in the same period of 2010. Gas production increased from 0 Mcf in the
first six months of 2009 to 152,379 Mcf in the same period of 2010. However, there was an audit adjustment made in the first quarter of 2009, which resulted in the recognition of $725,720 in gas
revenues associated with 107,416 Mcf of gas from a prior period. The natural gas sales price was $0 per Mcf in the first six months of 2009 compared to $5.18 per Mcf in the first six months of 2010.
Capital expenditures increased from $27,443 in the first six months of 2009 to $88,455 in the same period of 2010, due primarily to re-zoning and facility work during the first six months
of 2010. Operating expenses increased from $1,398,596 in the first six months of 2009 to $1,518,373 for the same period in 2010 primarily due to continuing repair costs related to damages inflicted by
Hurricane Ike.

Eugene
Island 339 net crude oil revenues decreased from $38,544 in the first six months of 2009 to $0 for the same period in 2010, due to a decrease in volumes from 318 barrels in the
first six months of 2009 to 0 barrels in the first six months of 2010. However, there was no actual crude oil production during the first six months of 2009 and such crude oil revenues and production
volumes are entirely from an audit adjustment made in the first quarter of 2009 and associated with a prior period. Gas revenues decreased from $170,231 in the first six months 2009 to $0 for the same
period in 2010, due to a decrease in natural gas volumes from 33,296 Mcf in the first six months of 2009 to 0 Mcf for the same period in 2010. However, there was no actual gas production during the
first six months of 2009 and such gas revenues and volumes are entirely from an audit adjustment made in the first quarter of 2009 and associated with a prior period. Capital expenditures decreased
from $180,089 in the first six months of 2009 to $(8,582) in the same period in 2010. The higher capital expenditures during the first six months of 2009 reflect costs associated with damages caused
by Hurricane Ike. Capital expenditures for the first six months of 2010 reflect credits of $8,582 associated with the workover of a well during a prior period and an invoice correction related to well
abandonment. Operating expenses decreased

18

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from
$14,220,452 in the first six months of 2009 to $5,684,176 in the same period in 2010, due primarily to less well and platform abandonment work being conducted in the first six months of 2010 as
compared to the first six months of 2009.

West
Cameron 643 gas revenues increased from ($4,603) in the first six months of 2009 to $5,244 for the same period in 2010. Gas volumes increased from (1,234) Mcf in the first six
months of 2009 to 0 Mcf for the same period in 2010. There was no actual gas production during the first six months of 2009 and 2010 as a result of the field being shut-in following
Hurricane Ike in September 2008. The revenues and volumes for the first six months of 2009 are a result of debits to correct an error in revenue allocation in August 2008. The positive revenues for
the first six months of 2010 are the result of a correction to a prior period audit adjustment made in the first quarter of 2009. Operating expenses decreased from $740,330 for the first six months of
2009 to $173,152 for the same period in 2010, and capital expenditures were $135,291 for the first six months of 2009 and $0 for the first six months of 2010, as the field was shut-in
after Hurricane Ike in September 2008 as a result of damages to a third-party transporter's pipeline.

East
Cameron 371 crude oil revenues were $0 for the first six months of 2009 and 2010 as a result of the field being shut-in following Hurricane Ike in September 2008.
Production was 0 barrels in the first six months of 2009 and 2010. Gas revenues were $0 for the first six months of 2009 and 2010 as a result of no volumes in the first six months of 2009 and 2010.
Capital expenditures were $0 in the first six months of 2009 and 2010. Operating expenses were $0 in the first six months of 2009 and 2010.

South
Timbalier 37/27 crude oil revenues increased from $116,021 in the first six months of 2009 to $167,377 for the same period in 2010 due to an increase in the average crude oil price
received from $48.16 per barrel in the first six months of 2009 to $75.77 per barrel for the same period in 2010. There was a decrease in crude oil production volumes to 2,209 barrels in the first six
months of 2010 from 2,409 barrels in the first six months of 2009. Gas revenues decreased from $23,341 in the first six months of 2009 to $21,933 in the first six months of 2010. There was an increase
in natural gas volumes from 4,046 Mcf in the first six months of 2009 to 4,298 Mcf in the first six months of 2010. The natural gas sales price was $5.77 per Mcf in the first six months of 2009
compared to $5.10 per Mcf in the first six months of 2010. Capital expenditures increased from $(55,435) in the first six months of 2009 to $16,119 in the first six months of 2010 after taking into
account a $56,263 credit in 2009 for a prior period audit adjustment. Operating expenses increased from $(19,298) in the first six months of 2009 to $19,128 in the first six months of 2010 after
taking into account a $36,992 credit in 2009 for a prior period audit adjustment.

Liquidity and Capital Resources

The Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. Total
future net revenues attributable to the Partnership's interest in the Royalty were estimated at $13.1 million as of October 31, 2009. However, there are not likely to be sufficient Net
Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable future. On October 7, 2008, the Trust announced that
production from the two most significant oil and gas properties associated with the Trust had ceased following damage inflicted by Hurricane Ike in September 2008. The Trust has not received a
distribution of Net Proceeds since December 2008. Consequently, the Trust has not made a distribution to Unit holders since January 9, 2009. On June 23, 2010, the Trust announced there
would be no trust distributions for the second quarter of 2010. As a result of the damage inflicted by

19

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Hurricane
Ike, Net Proceeds will continue to be severely impacted by reduced production, from historical levels, and the amount of expenditures incurred that are associated with such damages,
including the expenditures required to plug and abandon the wells on Eugene Island 339, and, as currently expected, to redevelop the facility at Eugene Island 339. Accordingly, there will not be
sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future.

The
platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike. Chevron is working on the plugging and abandonment of the existing wells, clearing debris and
otherwise dealing
with the remaining infrastructure, which activities are not expected to be completed until the second quarter of 2012. Chevron has informed the Corporate Trustee that Chevron presently intends to
pursue the redevelopment of platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the BOEM in response to Chevron's submission to the BOEM of a program to
restore production at Eugene Island 339; however, there is no obligation for Chevron to pursue such redevelopment. The costs for such a redevelopment would be significant. Failure or inability to
pursue such a redevelopment, and on the timeframes approved by the BOEM, could result in a loss of the lease. At this time, there can be no assurance that production will be restored at Eugene Island
339. See "Operations" for a more detailed discussion of Eugene Island 339.

Production
at Ship Shoal 182/183 ceased following damage inflicted by Hurricane Ike in September 2008. While the hurricane caused limited surface damage to the facilities at Ship Shoal
182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. The third-party transporter's natural
gas pipeline repairs were completed and gas sales at Ship Shoal 182/183 were restored on June 26, 2009. However, the pipeline was shut down in mid-September for additional repairs.
Production sales for both oil and natural gas at Ship Shoal 182 and 183 were restored on October 8, 2009 following completion of such additional repairs. Production ceased at Ship Shoal 182/183
in late March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Such pipeline was repaired and Ship Shoal 182/183 was reopened on May 1, 2010 after a 36-day
shut-in. See "Operations" for a more detailed discussion of Ship Shoal 182/183.

In
addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. Chevron
understands that the operator of West Cameron 643 submitted to the BOEM a request for an extension of the program to restore production but that such request was denied. Chevron also understands that
the plugging and abandonment of the wells and related infrastructure at West Cameron 643 is expected to commence in late 2010 or early 2011, with a deadline to complete such activities of
June 1, 2011. The field operator for East Cameron 371 has reported to Chevron that a review of the remaining reserves for East Cameron 371 has been conducted, and that the wells at East Cameron
371 have been depleted. The lease for East Cameron 371 expired on March 31, 2010 and the field operator has informed Chevron that field abandonment work, including the related wells, equipment
platforms and any field infrastructure, will commence within one year of such date. See "Operations" for a more detailed discussion of West Cameron 643 and East Cameron 371.

Future
Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the
operators of the Royalty Properties. The Trust's net portion of the aggregate cost to plug and abandon the wells subject to the royalty on Eugene Island 339 is estimated to be approximately
$13 million, approximately

20

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$8.1 million
of which had been incurred through June 30, 2010. If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust
will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest at a rate equal to one-fourth of
(i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate
at the end of the preceding quarterly period, during the deficit period. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net Proceeds since December 2008. For the
second quarter of 2010, under the terms of the Conveyance, gross proceeds for the Royalty Properties exceeded related development and production costs, with the Trust's portion of such excess equal to
approximately $265,000. However, as of June 30, 2010, aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of production
from the Royalty Properties by approximately $5.9 million. Significant development and production costs will continue to be incurred as Eugene Island 339 is redeveloped. Accordingly, there will
not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this time, the ultimate outcome of these various matters cannot be
determined. See "Operations."

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, economic conditions generally and
other variables.

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 1994, in anticipation of future periods when the cash received from the
Royalty may not be sufficient for payment of Trust expenses, the Trust determined, in accordance with the Trust Agreement, to begin further increasing the Trust's cash reserve each quarter. In the
first quarter of 1998, the Trust determined that the Trust's cash reserve was then sufficient 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 annual expenses of the Trust during each of the past three years was sufficient at such time to provide for future administrative
expenses in connection with the winding up of the Trust.

The
reserve amount at June 30, 2010 was $810,935, or approximately one times the average annual expenses of the Trust during the three-year period ended
June 30, 2010. The reserve amount at December 31, 2009 was $1,263,080, or approximately 1.7 times the average annual expenses of the Trust during the three-year period ended
December 31, 2009. As described herein, there are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. Absent the receipt of Net Proceeds or other
actions being taken, at some point, the Trust will not have sufficient funds to pay the liabilities of the Trust. While the ultimate outcome cannot be determined at this time, the Trust will likely
not receive a distribution of Net Proceeds prior to depleting its reserves for payment of obligations of the Trust. As such, the Trustees may take certain actions, discussed below, permitted under the
Trust Agreement, which could materially impact the Unit holders.

Pursuant
to the terms of the Trust Agreement, the Trustees are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that
cash on hand is

21

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not
sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no further distributions will be made to the Unit holders until the
indebtedness created by such borrowings has been paid in full. However, there can be no assurance as to the terms and conditions of any such financing, or that any such financing can actually be
obtained.

The
Trust Agreement further provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders
(a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise
their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

The
accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. The lack of Net Proceeds and the inability to maintain adequate cash
reserves raise substantial doubt about the Trust's ability to continue as a going concern (see Notes 4 and 6 to the financial statements). Certain potential alternatives available to the
Trustees are described in Note 6 to the financial statements. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Future Net Revenues and Termination of the Trust

Based on a reserve study provided to Chevron, as the Managing General Partner of the Partnership, by DeGolyer and MacNaughton,
independent petroleum engineers, as of October 31, 2009 future net revenues attributable to the Trust's royalty interests were estimated at $13.1 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, 2009 in order to correspond with distributions to
the Trust. Such reserve study also indicates that approximately 65% of the future net revenues from the Royalty Properties are expected to be received by the Trust by October 31, 2012. The
reserve study does not include reserves attributable to Eugene Island 339 or any capital expenditures for any redevelopment of Eugene Island 339. However, such reserve study does include the Trust's
share of the estimated total plugging and abandonment costs related to Eugene Island 339, with costs to the Trust relating thereto estimated to be approximately $13 million, approximately
$8.1 million of which had been incurred through June 30, 2010. 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. 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 Annual Report on Form 10-K for the year ended December 31, 2009. 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.

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Special Cost Escrow Account

The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling
platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in
the Conveyance, the amount of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net
revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit.
Such account is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated
production costs. Special Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been
paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than
125% of 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 2010, there were no funds released or
escrowed from the Special Cost Escrow account. As of June 30, 2010, $4,306,383 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. The discussion of the terms of the Conveyance and Special Cost Escrow account contained herein is qualified in its entirety by reference to the Conveyance
itself, which is an exhibit to this Form 10-Q and is available upon request from the Corporate Trustee.

Chevron,
in its capacity as 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.

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

23

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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)2010

2009Crude oil and condensate (bbls)


29,867


35,475Natural gas and gas products (Mcfe)


62,008


1,801Crude oil and condensate average price, per bbl

$
77.26

$
51.11Natural gas average price, per Mcf (excluding gas products)

$
6.03

$
6.29Crude oil and condensate revenues

$
2,307,559

$
1,813,293Natural gas and gas products revenues


386,258


21,761Production expenses


(1,571,593
)

(10,763,900
)Capital expenditures


(69,177
)

(10,964
)Undistributed net loss (income)(2)


(1,045,972
)

8,936,312Refund of (provision for) Special Cost Escrow


(7,075
)

3,498Net Proceeds





Royalty interest


x25
%

x25
%Partnership share





Trust interest


x99.99
%

x99.99
%Trust share of Royalty income

$


$



(1)Amounts
are based on actual production for the three-month period ended April 30 of each year, respectively.(2)Undistributed
net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the
Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will
not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued


24

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interest.
Undistributed net income represents positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners.


Royalty Properties
Six Months Ended
June 30,2010

2009Crude oil and condensate (bbls)


80,775


53,985Natural gas and gas products (Mcfe)


169,984


157,071Crude oil and condensate average price, per bbl

$
76.21

$
52.28Natural gas average price, per Mcf (excluding gas products)

$
5.17

$
6.32Crude oil and condensate revenues

$
6,155,478

$
2,822,575Natural gas and gas products revenues


928,890


1,031,988Production expenses


(7,832,533
)

(16,947,089
)Capital expenditures


(95,993
)

(287,388
)Undistributed net loss (income)(1)


843,396


13,291,668Refund of (provision for) Special Cost Escrow


762


88,247Net Proceeds





Royalty interest


x25
%

x25
%Partnership share





Trust interest


x99.99
%

x99.99
%Trust share of Royalty Income

$


$



(1)Undistributed
net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the
Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will
not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. Undistributed net income represents positive Net Proceeds,
generated during the respective period, but not distributed by the Working Interest Owners.




Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

The only assets of and sources of income to the Trust are cash and the Trust's interest in the Partnership, which is the holder of the
Royalty. Consequently, the Trust is exposed to market risk associated with the Royalty from fluctuations in oil and gas prices. Reference is also made to Note 2 of the Notes to Financial
Statements included in Item 1 of this Form 10-Q.

The
Trust may borrow money to pay expenses of the Trust. Additionally, if development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties,
the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest, at a rate equal to one-fourth of
(i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate
at the end of the preceding quarterly period, during the deficit period. Consequently, the Trust will be exposed to interest rate market risk should it borrow money to pay expenses and to the extent
that development and production costs of the Royalty exceed the proceeds

25

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of
production from the Royalty Properties. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net Proceeds since December 2008. For the second quarter of 2010, under the
terms of the Conveyance, gross proceeds for the Royalty Properties exceeded related development and production costs, with the Trust's portion of such excess equal to approximately $265,000. However,
as of June 30, 2010, aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of production from the Royalty Properties by
approximately $5.9 million.

Item 4.    Controls and Procedures.

Evaluation of disclosure controls and procedures.The Corporate Trustee maintains disclosure controls and procedures designed to ensure
that
information required to be disclosed by the Trust in the reports that it files or submits under the 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 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.

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 Item 1A. Risk Factors
"The Trustees and the Unit holders have no control over the operation or development of the Royalty Properties and have little influence over operation or development" and "The Trustees
rely upon 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, 2009 for a description of certain risks relating to these arrangements and reliance on 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 operation.

Changes in Internal Control Over Financial Reporting.During the three months ended June 30, 2010, there has been no change in the
Trust's
internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. 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.

26

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PART IIOTHER INFORMATION

Item 1A.    Risk Factors.

The Trust continues to utilize reserves to pay expenses, and there are not likely to be Net Proceeds distributed to the Trust for the foreseeable future. Absent the receipt
of Net Proceeds, or other actions being taken, at some point, the Trust will not have sufficient funds to pay the liabilities of the Trust. As such, the Trustees may take certain actions that could
materially impact the Unit holders, including borrowing money, selling all or a part of the Trust's interest in the Partnership, exercising their rights to dissolve the Partnership or causing the sale
by the Partnership of the Royalty owned by the Partnership.

The Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. The Trust
has not received a distribution of Net Proceeds since December 2008, and there are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. The Trust continues to
utilize reserves to pay expenses; however, as of June 30, 2010, those reserves were approximately one times the average annual expenses of the Trust during the three-year period
ended June 30, 2010. Absent the receipt of Net Proceeds, or other actions being taken, at some point, the Trust will not have sufficient funds to pay
the liabilities of the Trust. While the ultimate outcome cannot be determined at this time, the Trust will likely not receive a distribution of Net Proceeds prior to depleting its reserves for payment
of obligations of the Trust. As such, the Trustees may take certain actions that could materially impact the Unit holders. Such actions include borrowing money, selling all or a part of the Trust's
interest in the Partnership, exercising their rights to dissolve the Partnership or causing a sale by the Partnership of the Royalty owned by the Partnership. See "Management's Discussion and Analysis
of Financial Condition and Results of OperationsLiquidity and Capital Resources" under Item 2 of this Form 10-Q.

The recent Deepwater Horizon incident in the U.S. Gulf of Mexico and its consequences could have a material adverse effect on the Royalty income payable to the Trust.

On April 22, 2010, a deepwater U.S. Gulf of Mexico drilling rig, theDeepwater
Horizon, sank after an apparent blowout and fire at the Macondo wellsite. In May 2010, the U.S. Department of Interior implemented a six-month moratorium/suspension
on certain drilling activities in water depths greater than 500 feet in the U.S. Gulf of Mexico in response to such incident. Such moratorium/suspension is the subject of various legal and
administrative proceedings. The BOEM subsequently issued Notices to Lessees, or "NTLs," implementing additional safety and certification requirements applicable to drilling activities in the U.S. Gulf
of Mexico, imposed additional requirements with respect to development and production activities in the U.S. Gulf of Mexico and has delayed the approval of applications to drill in both
deep-water and shallow-water areas.

While
the Royalty Properties are located at water depths less than 500 feet, to the extent this incident results in federal legislation, policy, restrictions, or regulations that cause
delays or deter new drilling in the U.S. Gulf of Mexico, or that increase the costs of offshore production, the Royalty income payable to the Trust could be materially adversely affected. We cannot
predict at this time the impact, if any, that this incident may have on the operations of the Royalty Properties, particularly a redevelopment of Eugene Island 339, the Royalty income payable to the
Trust or on the financial condition of the Trust. However, drilling activity associated with the redevelopment of Eugene Island 339 has been suspended and the drilling rig moved off location pending
the approval of drilling permits

27

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under
the new guidelines issued by the BOEM on June 8, 2010 pursuant to NTL No. 2010-N05, "Increased Safety Measures for Energy Development on the OCS".

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)

0-06910

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)

0-06910

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)

0-06910

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)

0-06910

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)

0-06910

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)

0-06910

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)

0-06910

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)

0-06910

10(c)


28

---



SEC File or
Registration
Number

Exhibit
Number10
(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)

0-06910

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


29

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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 Mellon
    Trust Company, N.A.
Corporate TrusteeBy:

/s/ MIKE ULRICH Mike UlrichVice President


Date:
August 13, 2010

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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