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 March 31, 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 May 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.

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PART IFINANCIAL INFORMATION

Item 1.    Financial Statements.

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

March 31,
2010

December 31,
2009AssetsCash and cash equivalents

$
1,078,726

$
1,263,080Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,242,092 and $28,240,469, respectively


25,563


27,186Total assets

$
1,104,289

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

$


$
Reserve for future Trust expenses


1,078,726


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


25,563


27,186Total liabilities and Trust corpus

$
1,104,289

$
1,290,266


STATEMENTS OF DISTRIBUTABLE INCOME    (Unaudited)

Three Months
Ended March 31,2010

2009Royalty income

$


$
Interest income


121


576121


576(Increase)/decrease in reserve for future Trust expenses


184,354


331,016General and administrative expenses


(184,475
)

(331,592
)Distributable income





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

$
.000000

$
.000000


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STATEMENTS OF CHANGES IN TRUST CORPUS    (Unaudited)

Three Months
Ended March 31,2010

2009Trust corpus, beginning of period

$
27,186

$
31,338Distributable income





Distribution payable to Unit holders





Amortization of net overriding royalty interest


(1,623
)

(702
)Trust corpus, end of period

$
25,563

$
30,636


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 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:



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

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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 (the
"Individual Trustees"), as trustees (the "Trustees").

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
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 March 31, 2009 would substantially represent the revenues and
expenses from the Royalty Properties from November 2008 through January 2009. Similarly, any cash conveyed to the Trust from

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the
Royalty during the quarter ended March 31, 2010 would substantially represent the revenues and expenses from the Royalty Properties from November 2009 through January 2010.
However, there was no cash conveyed to the Trust from the Royalty Properties from either November 2008 through January 2009 or November 2009 through January 2010. The
financial and operating information included in this Form 10-Q for the three months ended March 31, 2010 represents financial and operating information with respect to the
Royalty Properties for the months of November and December 2009 and January 2010. 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.

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.

In
May 2009, the Financial Accounting Standards Board (FASB) issued what is codified as FASB ASC 855, Subsequent Events ("FASB ASC 855"). FASB ASC 855
establishes principles and standards related to the accounting for and disclosure of events that occur after the date of the balance sheet included in financial statements being presented, but before
such financial statements are issued. FASB

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ASC 855
requires an entity to recognize, in the financial statements, subsequent events that provide additional information regarding conditions that existed at the balance sheet date.
Subsequent events that provide information about conditions that did not exist at the balance sheet date are not to be recognized in the financial statements under FASB ASC 855. FASB
ASC 855 is effective for interim and annual reporting periods ending after June 15, 2009. The Trust adopted this standard effective as of June 30, 2009. The adoption of FASB
ASC 855 did not have a material effect on the Trust's financial statements. Subsequent events were evaluated through the date that these financial statements were issued.

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.

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

Quarter

Distribution2010:First

$
02009:Fourth

$
0Third


0Second


0First


0


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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 and March 23, 2010, the Trust
announced there would be no trust distributions for the second, third and fourth quarters of 2009 or the first quarter 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 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 million of which had been incurred through March 31, 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 as development and production costs of the Royalty for each Quarterly Period since November 2008 have exceeded the proceeds
of production from the Royalty Properties. As of March 31, 2010, development and production costs associated with the Royalty exceeded the proceeds of production from the Royalty Properties by
approximately $6.1 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

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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 quarter of 2010, there were no funds released or escrowed from the Special Cost Escrow account.
As of March 31, 2010, $4,306,084 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 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 first quarter of 2010, the Trust used
$184,354 from the reserve account for current expenses, leaving a reserve balance as of March 31, 2010 of $1,078,726, or approximately 1.4 times the average annual expenses of the Trust during
the three-year period ended March 31, 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.

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.

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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 March 31, 2010 and 2009

There were no distributions to the Unit holders for the three months ended March 31, 2010 and 2009.

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Crude
oil and condensate revenues increased $2,838,637, or 281%, to $3,847,919 in the first quarter of 2010 from $1,009,282 in the first quarter of 2009, due primarily to increased
production at Ship Shoal 182/183 and increased realized prices. Oil volumes during the first quarter of 2010 increased 175% to 50,908 barrels, compared to 18,510 barrels of oil produced in the first
quarter of 2009. The revenues and volumes for the first quarter of 2009 reflect credits associated with an audit of prior periods for $37,705 in revenues and 311 barrels. The average price received
for crude oil and condensate increased 39%, or $21.06, to $75.59 per barrel in the first quarter of 2010 from $54.53 per barrel in the first quarter of 2009 (after taking into account a minor prior
period pricing adjustment in 2009).

Gas
revenues decreased $366,530, or 44%, to $461,131 in the first quarter of 2010 from $827,661 in the first quarter of 2009. Gas volumes during the first quarter of 2010 decreased 25%
to 98,850 Mcf, compared to 130,986 Mcf produced in the first quarter of 2009. The revenues and volumes for the first quarter of 2009 reflect credits associated with an audit of prior periods for
$813,087 in revenues and 128,945 Mcf of gas. The average price received for natural gas was $4.66 per Mcf in the first quarter of 2010 compared to $7.14 per Mcf in the first quarter of 2009. After
taking into account prior period audit adjustments, the average price for natural gas for the first quarter of 2009 was effectively $6.32 per Mcf. Gas products revenue decreased $101,064, or 55%, to
$81,501 in the first quarter of 2010 from $182,565 in the first quarter of 2009. Gas products volumes during the first quarter of 2010 decreased 62% to 63,885 gallons, compared to 169,990 gallons in
the first quarter of 2009. The revenues and volumes for the first quarter of 2009 reflect credits associated with an audit of prior periods for $180,269 in revenues and 168,912 gallons.

Capital
expenditures decreased by $249,609, or 90%, from $276,425 in the first quarter of 2009 to $26,816 in the first quarter of 2010. The higher amount of capital expenditures during
the first quarter of 2009 related primarily to repair of damages caused by Hurricane Ike in September 2008.

Operating
expenses increased by $12,028, or 0.2%, from $5,937,665 in the first quarter of 2009 to $5,949,693 in the first quarter of 2010.

The
Royalty Properties had undistributed net loss of $1,889,368 in the first quarter of 2010.

In
the first quarter of 2010, there were no funds released or escrowed from the Special Cost Escrow account. As of March 31, 2010, $4,306,084 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 first quarter of 2009, there were no funds released or escrowed from the Special Cost Escrow account. As of March 31, 2009, $4,305,190 remained in 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 annual expenses of the Trust during each of the past three years was sufficient to provide for future

10

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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 first quarter
of 2010, the Trust used $184,354 from the reserve for current expenses, leaving a reserve balance as of March 31, 2010 of $1,078,726, or approximately 1.4 times the average annual expenses of
the Trust during the three-year period ended March 31, 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.

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 first 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 million of which had been
incurred through March 31, 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 (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. A lease operator may seek approval from the regional supervisor of the Minerals Management Service, or "MMS," to allow additional time to restore production. 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 MMS
in response to Chevron's submission to the MMS of a program to restore production at Eugene Island 339. The activity schedule approved by the MMS contemplates, among other things, completion of
front-end engineering and design work by the end of July 2010, an awarding of fabrication contracts for platform, substructure and equipment by the end of November 2010, and

11

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commencement
of production ultimately occurring by the end of October 2012. Chevron is required to provide the MMS with periodic updates on Chevron's progress on such redevelopment. The approval by
the MMS expires by its terms on November 30, 2010, and Chevron would need to request an extension of such approval from the MMS in order to complete the proposed redevelopment, given that the
activity schedule contemplates activity through October 2012. In December 2009, Chevron entered into an agreement with a third party for the redevelopment of Eugene Island Blocks 338 and 339. Although
Eugene Island Block 338 is not a Royalty Property, the current plan is to develop the two leases as one project. Three wells are planned to be commenced from a common open water location in Eugene 338
in the second quarter of 2010. The information derived from these wells will be used, in part, to determine the size of the platform and topside facilities (production processing equipment) that are
to be used for both Eugene Island 338 and Eugene Island 339. If a platform is set, the current plan is to drill additional wells in Eugene Island 338 and Eugene Island 339 from that
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 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 pursue such a redevelopment, 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 MMS, 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 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

12

---



production
at West Cameron 643 due to the damages inflicted by Hurricane Ike to a third-party transporter's pipeline, Hilcorp submitted to the MMS a program to restore production at West Cameron 643
and that such request has been granted. Chevron also understands that the pipeline for West Cameron 643 is in the process of being restored, although such pipeline is not expected to be able to take
production until the third quarter of 2010. The approval by the MMS expires by its terms
on May 31, 2010, and Hilcorp would need to request an extension of such approval from the MMS given that the pipeline is not expected to be able to take production until the third quarter of
2010. At this point in time, there can be no assurance as to when, or if at all, production may be restored at West Cameron 643. 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. At this time, the field operator at East Cameron 371 has not made a
decision regarding field abandonment, including the related wells, equipment platforms and any field infrastructure.

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. The adjustments resulting from such audit review were completed in the second quarter of 2009.

Three Months Ended March 31, 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.

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 $909,371 in the first quarter of 2009 to $3,758,902 in the first quarter of 2010, due to an increase in net crude oil production from
17,124 barrels in the first quarter of 2009 to 49,708 barrels in the first quarter of 2010. The average crude oil price received also increased from $53.11 per barrel in the first quarter of 2009 to
$75.62 per barrel for the same period in 2010. Gas revenues decreased from $725,720 in the first quarter of 2009 to $456,469 in the first quarter of 2010. Gas production increased from 0 Mcf in the
first quarter of 2009 to 97,461 Mcf in the first quarter of 2010. The lack of gas production in the first quarter of 2009 was due to the cessation of production in September 2008 resulting from
damages inflicted by Hurricane Ike. 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. Capital expenditures increased from $20,461 in the first quarter of 2009 to $35,005 in the first quarter of 2010 primarily due to re-zoning and workover projects. The
$20,461 in capital expenditures for the first quarter of 2009 reflects a credit of $3,531 as a prior period audit adjustment. Operating expenses decreased from

13

---



$699,769
in the first quarter of 2009 to $671,826 for the same period in 2010 due to a decrease in operating and repair costs related to damages inflicted by Hurricane Ike.

Eugene
Island 339 net crude oil revenues decreased from $38,544 in the first quarter of 2009 to $0 for the same period in 2010 due to a decrease in crude oil production volumes to 0
barrels in the first quarter of 2010 from 318 barrels in the first quarter of 2009. However, there was no actual crude oil production during the first quarter 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 quarter 2009 to $0 in
the first quarter of 2010. There was a decrease in natural gas volumes from 33,296 Mcf in the first quarter of 2009 to 0 Mcf in the first quarter of 2010. However, there was no actual gas production
during the first quarter 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 $176,294 in the first quarter of 2009 to $(8,255) in the first quarter of 2010. Capital expenditures made during the first quarter of 2009 relate primarily to damages inflicted by
Hurricane Ike. Capital expenditures for the first quarter of 2010 reflect a credit of $8,255 associated with the workover of a well during a prior period. Operating expenses increased from $4,945,522
in the first quarter of 2009 to $5,142,748 in the first quarter of 2010 due to well abandonment costs incurred as a result of Hurricane Ike.

West
Cameron 643 gas revenues increased from $(82,915) in the first quarter of 2009 to $0 in the first quarter of 2010. Gas volumes increased from (11,767) Mcf in the first quarter of
2009 to 0 Mcf for the same period in 2010. There was no actual gas production during the first 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 first quarter 2009 are a result of an audit adjustment associated with prior periods. Operating expenses decreased from $322,898 in the first
quarter of 2009 to $127,008
for the same period in 2010, and capital expenditures decreased from $135,060 in the first quarter of 2009 to $0 for the same period in 2010.

East
Cameron 371 crude oil revenues were $0 in the first 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 first quarter of 2009 and 2010. Gas revenues were $0 in the first quarter of 2009 and 2010 as a result of no gas volumes in the first quarter 2009 and 2010. Operating expenses
were $0 in the first quarter of 2009 and 2010.

South
Timbalier 37/27 crude oil revenues increased from $53,724 in the first quarter of 2009 to $82,447 for the same period in 2010 due primarily to an increase in realized oil prices
and an increase in oil production volumes. There was an increase in crude oil production volumes to 1,106 barrels in the first quarter of 2010 from 1,000 barrels in the first quarter of 2009. The
average crude oil price received increased from $53.73 per barrel in the first quarter of 2009 to $74.55 per barrel in the first quarter of 2010. Gas revenues decreased from $10,126 in the first
quarter 2009 to $4,477 in the first quarter of 2010 due primarily to a decrease in gas prices realized and a decrease in gas production. There was a decrease in natural gas volumes from 1,442 Mcf in
the first quarter of 2009 to 1,339 Mcf in the first quarter of 2010. The average natural gas price received decreased from $7.02 per Mcf in the first quarter of 2009 to $3.34 per Mcf in the first
quarter of 2010. Capital expenditures increased from $(55,390) in the first quarter of 2009 to $67 in the first quarter of 2010. Capital expenditures for the first quarter of 2009 reflect a $56,263
credit related to a prior period audit adjustment. Operating expenses increased from $(30,524) in the first quarter of 2009 to $8,111 in the first quarter of 2010.

14

---



Operating
expenses for the first quarter of 2009 reflect a $36,992 credit related to 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 March 23,
2010, the Trust announced there would be no trust distributions for the first quarter of 2010. 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. 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 first 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 MMS in response to Chevron's submission to the
MMS 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 MMS, 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. 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 pipeline for West Cameron 643 is in the process of being restored, although such pipeline is not expected to be able to take production until the third quarter of 2010. At this
point in time, there can be no assurance as to when, of if at all, production may be restored at West Cameron

15

---



643.
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. 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 $8 million of which had been incurred through March 31, 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 as development and production costs of the Royalty for each Quarterly Period since November 2008 have exceeded the proceeds of production from the Royalty Properties. As of
March 31, 2010, development and production costs of the Royalty exceeded the proceeds of production from the Royalty Properties by approximately $6.1 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 March 31, 2010 was $1,078,726, or approximately 1.4 times the average annual expenses of the Trust during the three-year period ended
March 31, 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

16

---



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.

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.

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 million of which had been incurred through March 31, 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.

17

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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 first quarter of 2010, there were no funds released or
escrowed from the Special Cost Escrow account. As of March 31, 2010, $4,306,084 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

18

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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
March 31,(1)2010

2009Crude oil and condensate (bbls)


50,908


18,524Natural gas and gas products (Mcfe)


107,976


155,270Crude oil and condensate average price, per bbl

$
75.59

$
54.53Natural gas average price, per Mcf (excluding gas products)

$
4.66

$
6.32Crude oil and condensate revenues

$
3,847,919

$
1,009,282Natural gas and gas products revenues


542,632


1,010,227Production expenses


(6,260,940
)

(6,183,189
)Capital expenditures


(26,816
)

(276,425
)Undistributed net loss (income)(2)


1,889,368


4,355,356Refund of (provision for) Special Cost Escrow


7,837


84,749Net Proceeds





Royalty interest


x25
%

x25
%Partnership share





Trust interest


x99.99
%

x99.99
%Trust share of Royalty income

$


$



---

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

19

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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 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 as development and production costs of the Royalty for each Quarterly Period since November 2008 have exceeded the proceeds of production
from the Royalty Properties. As of March 31, 2010, development and production costs of the Royalty exceeded the proceeds of production from the Royalty Properties by approximately
$6.1 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 March 31, 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.

20

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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 March 31, 2010, those reserves were approximately 1.4 times the average annual expenses of the Trust during the three-year period ended
March 31, 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.

Any extended moratorium on new drilling in the U.S. Gulf of Mexico, or any resulting additional regulations, could have a material adverse effect on the Royalty income
payable to the Trust.

As has been widely reported, on April 22, 2010, a semisubmersible drilling rig, theDeepwater
Horizon, sank in the U.S. Gulf of Mexico after an explosion and fire onboard the rig that began on April 20, 2010. Although attempts are being made to seal the well,
hydrocarbons have been leaking into the U.S. Gulf of Mexico and the spill area continues to grow.

On
April 30, 2010, officials in the Obama Administration indicated that federal agencies would not authorize new offshore drilling in U.S. waters pending review of the oil spill
caused by the sinking of theDeepwater Horizon. This announcement states that no additional drilling will be authorized until the administration
completes its review of the cause of the explosion and determination of whether the explosion was unique and preventable. If this moratorium continues for an extended period, or the review 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.

21

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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)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)


0-06910


10
(d)


22

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SEC File or
Registration
Number

Exhibit
Number31



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


23

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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 PresidentDate: May 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.

24

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