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, 2009Oro

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 ý

Non-accelerated filer o (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 7, 2009, 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 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, 2008 under Part I, Item 1A "Risk Factors." All subsequent written and oral forward-looking statements attributable to the Trust or persons acting
on its behalf are expressly qualified in their entirety by the Cautionary Statements.

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PART IFINANCIAL INFORMATION

Item 1.    Financial Statements.

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

March 31,
2009

December 31,
2008AssetsCash and cash equivalents

$
1,902,275

$
2,973,140Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,237,019 and $28,236,317, respectively


30,636


31,338Total assets

$
1,932,911

$
3,004,478Liabilities and Trust CorpusDistribution payable to Unit holders

$


$
739,849Reserve for future Trust expenses


1,902,275


2,233,291Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)


30,636


31,338Total liabilities and Trust corpus

$
1,932,911

$
3,004,478


STATEMENTS OF DISTRIBUTABLE INCOME    (Unaudited)

Three Months
Ended March 31,2009

2008Royalty income

$


$
5,067,521Interest income


576


11,260576


5,078,781(Increase)/decrease in reserve for future Trust expenses


331,016


(361,721
)General and administrative expenses


(331,592
)

(248,017
)Distributable income

$


$
4,469,043Distributions per Unit (4,751,510 Units)

$
.000000

$
.940552


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STATEMENTS OF CHANGES IN TRUST CORPUS    (Unaudited)

Three Months
Ended March 31,2009

2008Trust corpus, beginning of period

$
31,338

$
40,197Distributable income





4,469,043Distribution payable to Unit holders





(4,469,043
)Amortization of net overriding royalty interest


(702
)

(2,588
)Trust corpus, end of period

$
30,636

$
37,609


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 all of the corporate trust business of JPMorgan Chase (formerly known as The Chase
Manhattan

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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, 2008.

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 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, the cash conveyed to the Trust from the Royalty during the quarter ended March 31, 2008 substantially represents the revenues and expenses from the Royalty Properties from
November 2007 through January 2008. There was no cash conveyed to the Trust from the Royalty Properties from November 2008 through January 2009. The financial and operating information included in
this Form 10-Q for the three months ended March 31, 2009 represents financial and operating information

4

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with
respect to the Royalty Properties for the months of November and December 2008 and January 2009. 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 (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 and other variables. The
Trust does not enter into any hedging transactions on future production.

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

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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 2009 and 2008.

Quarter

Distribution2009:First

$
02008:Fourth

$
739,849Third


5,470,387Second


2,619,375First


4,469,043


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 first quarter distribution. Future distributions are expected to be severely negatively impacted, by both reduced production and increased expenditures required to remediate, repair and,
perhaps, restore platforms and wells. 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. Development activities may not generate sufficient additional revenue to repay the costs. Accordingly, there
may not be sufficient Net Proceeds from the Royalty Properties to make a particular distribution. At this time, the ultimate outcome of these matters cannot be determined.

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

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interest.
Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to
as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated production costs. Special Cost Escrow
funds will generally be utilized to pay Special Costs to the extent there are not adequate current net profits interest to pay such costs. Special Costs that have been paid are no longer included in
the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of estimated future
Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When
there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow
account will also be released when the balance in such account exceeds 125% of estimated future Special Costs. In the 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. The funds held in the Special Cost Escrow account are not reflected in the financial
statements of the Trust.

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 maintains a cash reserve, equal to approximately three times the average expenses of the Trust during each of the past three
years, to provide for future administrative expenses in connection with the winding up of the Trust. During the first quarter of 2009, the Trust used $331,016 from the reserve account for current
expenses, leaving a reserve balance of $1,902,275 as of March 31, 2009. The reserve amount at December 31, 2008 was $2,233,291.

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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 ongoing 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. See
"Operational Review".

Three Months Ended March 31, 2009 and 2008

There were no distributions to the Unit holders for the three months ended March 31, 2009 as compared to a distribution of
$4,469,043, or $0.940552 per Unit, for the same period in 2008.

Crude
oil and condensate revenues decreased $10,953,540, or 92%, to $1,009,282 in the first quarter of 2009 from $11,962,822 in the first quarter of 2008, due primarily to decreases in
production resulting from damages caused by Hurricane Ike. Oil volumes during the first quarter of 2009 decreased 86% to 18,510 barrels, compared to 133,415 barrels of oil produced in the first
quarter of 2008. The volumes and revenues for 2009 reflect credits associated with an audit of prior periods for 311 barrels and $37,705 in revenues; the volumes and revenues for 2008 reflect credits
associated with

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prior
period audit adjustments for 949 barrels and $173,148 in revenues. The average price received for crude oil and condensate also decreased 39%, or $35.14, to $54.53 per barrel in the first
quarter of 2009 from $89.67 per barrel in the first quarter of 2008 (after taking into account minor prior period pricing adjustments in both periods).

Gas
revenues decreased $2,405,517, or 75%, to $827,661 in the first quarter of 2009 from $3,233,178 in the first quarter of 2008, due primarily to damages caused by Hurricane Ike in
September
2008. Gas volumes during the first quarter of 2009 decreased 71% to 130,986 Mcf, compared to 453,760 Mcf produced in the first quarter of 2008. The volumes and revenues for 2009 reflect credits
associated with an audit of prior periods for 128,945 Mcf of gas and $813,087 in revenues; the volumes and revenues for 2008 reflect credits associated with prior period audit adjustments for 20,399
Mcf of gas and $126,864 in revenues. The average price received for natural gas was $7.14 per Mcf in the first quarter of 2009 compared to $7.13 per Mcf in the first quarter of 2008. 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 $984,869, to $182,565 in the first
quarter of 2009 from $1,167,434 in the first quarter of 2008, due primarily to a decrease in production volume to 169,990 gallons from 858,370 gallons.

Capital
expenditures increased by $702,102, from ($425,677) in the first quarter of 2008 to $276,425 in the first quarter of 2009. Reflected within the capital expenditures for 2008 is a
refund of $495,000 for certain prior period capital expenditures from the Working Interest Owners (with the Trust having a
net benefit associated therewith of $123,900) resulting from the audit by the independent oil and gas accounting firm as further described herein.

Operating
expenses increased by $4,505,907, or 315%, from $1,431,758 in the first quarter of 2008 to $5,937,665 in the first quarter of 2009, primarily as a result of well abandonment
costs at Eugene Island 339 as a result of Hurricane Ike.

The
Royalty Properties had undistributed net loss of $4,355,356 in the first quarter of 2009.

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. 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 2008, there was a net release of funds from the Special Cost Escrow account. The Trust's share of the funds released was approximately $1,318,188. The net release
of funds was primarily a result of current estimates of future abandonment costs, future capital expenditures, future production costs, future net revenues and current Net Proceeds. As of
March 31, 2008, $5,395,376 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

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expenses
of the Trust during each of the past three years was sufficient to provide for future administrative expenses in connection with the winding up of the Trust. During the first quarter of 2009,
the Trust used $331,016 from the reserve for current expenses, leaving a reserve balance of $1,902,275 as of March 31, 2009. The reserve amount at December 31, 2008 was $2,233,291.

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 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 reserve study of 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 proceeding to plug and abandon the existing wells, to clear debris and otherwise to deal with the
remaining infrastructure, with estimated costs relating thereto for 2009 alone of approximately $61 million. In order to restore production, Chevron expects that it would need to redevelop the
facility and drill new wells. Chevron is still assessing its alternatives and the economic feasibility of restoring production at the property. At this point in time, there can be no assurance as to
how or when, or if at all, production may be restored at Eugene Island 339. 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), or the lease will be terminated. A lease operator may seek approval from the
regional supervisor of the Mineral Management Service to allow additional time to restore production. Chevron submitted such a request with respect to Eugene Island 339 and, like other lessees dealing
with the effects of Hurricane Ike, was granted an extension until September 6, 2009 to submit a commitment to restore production, which would still have to be approved by the Mineral Management
Service. As stated above, Chevron is still assessing its alternatives, and Chevron has not made a decision whether to submit any such commitment to restore production. There can be no assurance that
production at Eugene Island 339 will be restored.

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 more productive wells on the
properties produce both oil and gas, and there is no downstream transmission available for any gas produced from the wells. Crude oil

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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, with an average rate of daily oil production from November 20, 2008 through
January 31, 2009 of approximately 831 barrels per day. The volume of oil production that can be produced is limited by the amount of gas that is also produced by the oil wells. Production is
expected to remain limited until the natural gas pipeline is fully repaired and tested, which is anticipated to occur in the second quarter of 2009, but which is also in the control of the pipeline
owner. There may also be related regulatory approval requirements that must be satisfied before gas transportation may commence. At this point in time, there can be no assurance as to when, or if at
all, gas production may be restored at 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. The
Managing General Partner of the Partnership understands that the pipelines are in the process of being restored; however, the pipeline for West Cameron 643 is not expected to be able to take
production until at least the end of 2009. 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 or East Cameron 371.

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. Based on the initial report of the accounting firm, the Trustees believe that certain errors in the books and records had occurred and are
involved in ongoing discussions with such Working Interest Owners to resolve these items. As part of this ongoing process, certain adjustments to revenues, production volumes, prices and capital
expenditures have occurred, and references herein to an audit of prior periods refers to the audit described in this paragraph. Such audit resulted in an additional cash distribution to the Trust
during the first quarter of 2008. These amounts are comprised of a one-time increase of approximately $31,716 in gas revenues, a one-time increase of approximately $43,287 in
oil revenues, and a one-time credit of approximately $123,900 in capital expenditures. Additional amounts related to the audit were included in later distributions to the Trust during
2008. Additional credits were 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. No assurance can be provided as to the ultimate outcome of the remaining items under discussion.

Three Months Ended March 31, 2009 and 2008

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 decreased from $6,170,577 in the first quarter of 2008 to $909,371 in the first quarter of 2009, due to a decrease in net crude oil production from
67,715 barrels

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in
the first quarter of 2008, which included an upward adjustment of 178 barrels relating to 2007 production, to 17,124 barrels in the first quarter of 2009. The inclusion of such adjustment for the
178 barrels resulted in an increase in revenues for 2008 of $46,630. The average crude oil price received also decreased from $91.13 per barrel in the first quarter of 2008 to $53.11 per barrel for
the same period in 2009. Gas revenues decreased from $1,672,719 in the first quarter of 2008 to $725,720 in the first quarter of 2009. Gas production decreased from 234,874 Mcf in the first quarter of
2008, which included an upward adjustment of 19,999 Mcf relating to 2007 production, to 0 Mcf in the first quarter of 2009 due to the cessation of production in September 2009 resulting from damages
inflicted by Hurricane Ike. 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 inclusion of such adjustment for the 19,999 Mcf in 2008 resulted in an increase in revenues for 2008 of $123,946. Capital expenditures increased from $(468,226) in the first
quarter of 2008 to $20,461 in the first quarter of 2009 primarily due to an audit credit in the first quarter of 2008 of $495,600 relating to prior periods. 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 increased from $565,955 in the first quarter of 2008 to $699,769 for the same period in 2009
due to an increase in operating and repair costs related to damages inflicted by Hurricane Ike.

Eugene
Island 339 net crude oil revenues decreased from $5,527,574 in the first quarter of 2008 to $38,544 for the same period in 2009 due to a decrease in crude oil production volumes
to 318 barrels in the first quarter of 2009 from 62,458 barrels in the first quarter of 2008. 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. The oil revenues for 2008 reflect a $81,750 credit relating
to prior periods. Gas revenues decreased from $991,774 in the first quarter 2008 to $170,231 in the first quarter of 2009. There was a decrease in natural gas volumes from 141,609 Mcf in the first
quarter of 2008 to 33,296 Mcf in the first quarter of 2009. 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 increased from $6,059 in the first quarter of 2008 to $176,294 in the first quarter of 2009 due to
costs related to Hurricane Ike. Operating expenses increased from $393,089 in the first quarter of 2008 to $4,945,522 in the first quarter of 2009 due to well abandonment costs incurred as a result of
Hurricane Ike.

West
Cameron 643 gas revenues decreased from $297,274 in the first quarter of 2008 to $(82,915) in the first quarter of 2009. Gas volumes decreased from 42,188 Mcf in the first quarter
of 2008 to (11,767) Mcf for the same period in 2009. There was no actual gas production during the first quarter of 2009 and the revenues and volumes for the first quarter 2009 are a result of an
audit adjustment
associated with prior periods. Operating expenses decreased from $166,499 in the first quarter of 2008 to $0 for the same period in 2009, and capital expenditures were $0 in the first quarter of 2008
and 2009.

East
Cameron 371 crude oil revenues decreased from $47,741 in the first quarter of 2008 to $0 in the first quarter of 2009 as a result of the field being shut-in following
Hurricane Ike in September 2008. Production decreased from 528 barrels in the first quarter of 2008 to 0 barrels for the same period in 2009. Gas revenues decreased from $247,946 in the first quarter
of 2008 to $0 in the first quarter of 2009 as a result of the decrease in gas volumes from 31,863 Mcf in the first quarter of 2008

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to
0 Mcf for the same period in 2009. Operating expenses decreased from $280,190 in the first quarter of 2008 to $0 in the first quarter of 2009.

South
Timbalier 37/27 crude oil revenues decreased from $170,042 in the first quarter of 2008 to $53,724 for the same period in 2009 due to a 32-day well shut-in
for compressor repairs. There was a decrease in crude oil production volumes to 1,000 barrels in the first quarter of 2009 from 1,921 barrels in the first quarter of 2008. Gas revenues decreased from
$22,188 in the first quarter 2008 to $10,126 in the first quarter of 2009. There was a decrease in natural gas volumes from 3,148 Mcf in the first quarter of 2008 to 1,442 Mcf in the first quarter of
2009. Capital expenditures decreased from $36,930 in the first quarter of 2008 to $(55,390) in the first quarter of 2009 after taking into account a $56,263 credit in 2009 for a prior period audit
adjustment. Operating expenses decreased from $26,024 in the first quarter of 2008 to $(30,524) in the first quarter of 2009 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.

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 platforms and wells on Eugene Island 339 were completely destroyed by
Hurricane Ike. While Hurricane Ike 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 more productive wells on the properties produce both oil and gas, and there is no downstream transmission available for any gas produced
from the wells. There can be no assurance that production at Eugene Island 339 will be restored. While production is expected to remain limited at Ship Shoal 182/183 until the natural gas pipeline is
fully repaired and tested, which is anticipated to occur in the second quarter of 2009, there can be no assurance as to when, or if at all, meaningful production may be restored at 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. The
Managing General Partner of the Partnership understands that the pipelines are in the process of being restored; however, the pipeline for West Cameron 643 is not expected to be able to take
production until at least the end of 2009. 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 or East Cameron 371.

On
December 19, 2008, the Trust announced its fourth quarter distribution of approximately $0.7 million, which was paid on January 9, 2009. Based on the damage
caused by Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively impacted, although there were funds available for distribution given that there was
some production from Eugene Island 339 and Ship Shoal 182/183 in August and September 2008. On March 25, 2009, the Trust announced that there would be no trust distribution for the first
quarter of 2009. There were no Net Proceeds distributed to the Trust for the first quarter of 2009. Future distributions by the Trust are expected to be severely negatively impacted, and there may not
be sufficient Net Proceeds from the Royalty Properties to make one or more future distributions. At this time, the ultimate outcome of these various matters cannot be determined.

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Future
Net Proceeds may take into account the Trust's share of project costs and other related expenditures that are not covered by insurance of the operator of the Royalty Properties.
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. Development activities may
not generate sufficient
additional revenue to repay the costs. Accordingly, there may not be sufficient Net Proceeds to make a particular distribution.

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.

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.

Future Net Revenues and Termination of the Trust

Based on a reserve study provided to the Trust by DeGolyer and MacNaughton, independent petroleum engineers, as of October 31,
2008 future net revenues attributable to the Trust's royalty interests were estimated at $24.2 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, 2008 in order to correspond with distributions to the Trust. Such reserve study also indicates that
approximately 40% of the future net revenues from the Royalty Properties are expected to be received by the Trust during the next three years. Solely for purposes of being able to complete the reserve
study so that the Trust could file its Form 10-K for the year ended December 31, 2008, DeGolyer and MacNaughton assumed that Eugene Island 339 will not be redeveloped. As
such, the reserve study does not include any reserves or values attributable to Eugene Island 339, nor does it include the Trust's percentage share of the total plugging and abandonment costs related
to Eugene Island 339, with such costs for 2009 alone estimated to be approximately $61 million. The assumption was made by DeGolyer and MacNaughton because Chevron had not made a decision
regarding any redevelopment of Eugene Island 339 and such decision would impact the treatment of Eugene Island 339 for purposes of preparing a reserve study for the Partnership. 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

14

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year
ended December 31, 2008. The Trust's Form 10-K is available at the website of the Securities and Exchange Commission ("SEC") at www.sec.govor upon request from the Corporate Trustee.

Special Cost Escrow Account

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

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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)2009

2008Crude oil and condensate (bbls)


18,524


133,415Natural gas and gas products (Mcfe)


155,270


576,384Crude oil and condensate average price, per bbl

$
54.53

$
89.67Natural gas average price, per Mcf (excluding gas products)

$
6.32

$
7.13Crude oil and condensate revenues

$
1,009,282

$
11,962,822Natural gas and gas products revenues


1,010,227


4,400,612Production expenses


(6,183,189
)

(1,962,573
)Capital expenditures


(276,425
)

425,677Undistributed net loss (income)(2)


4,355,356


(115,819
)Refund of (provision for) Special Cost Escrow


84,749


5,561,392Net Proceeds





20,272,111Royalty interest


x25
%

x25
%Partnership share





5,068,028Trust interest


x99.99
%

x99.99
%Trust share of Royalty income

$


$
5,067,521


---

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.

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

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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, 2008 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, 2009, 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.

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PART IIOTHER INFORMATION

Item 1A.    Risk Factors.

There have not been any material changes from risk factors previously disclosed in the Trust's response to Item 1A of
Part 1 of the Trust's Annual Report on Form 10-K for the year ended December 31, 2008.

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)


18

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SEC File or
Registration
Number

Exhibit
Number10
(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)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


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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 8, 2009


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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