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 September 30, 2010Oro

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


Commission File Number: 0-06910



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

Texas(State or other jurisdiction of
incorporation or organization)

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

78701(Zip Code)


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

Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ý    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit and post such files). Yes o    No o

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

Large accelerated filer o

Accelerated filer o

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

Smaller reporting company o


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

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



---





NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act
of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-Q
are forward-looking statements. Although Chevron USA, Inc., the Managing General Partner of the TEL Offshore Trust Partnership, has advised the Trust that the Managing General Partner believes
that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors
that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-Q, including, without limitation, in conjunction with
the forward-looking statements included in this Form 10-Q. A summary of certain principal risks and Cautionary Statements is also included in the Trust's Annual Report on
Form 10-K for the year ended December 31, 2009 under Part I, Item 1A "Risk Factors" and in Part II, Item 1A of this Form 10-Q.
All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements.

i

---





PART IFINANCIAL INFORMATION

Item 1.    Financial Statements.

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

September 30,
2010

December 31,
2009AssetsCash and cash equivalents

$
573,151

$
1,263,080Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,244,286 and $28,240,469, respectively


23,369


27,186Total assets

$
596,520

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

$


$
Reserve for future Trust expenses


573,151


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


23,369


27,186Total liabilities and Trust corpus

$
596,520

$
1,290,266


STATEMENTS OF DISTRIBUTABLE INCOME        (Unaudited)

Three Months Ended
September 30,

Nine Months Ended
September 30,2010

2009

2010

2009Royalty income

$


$


$


$
Interest income


20


203


168


1,15820


203


168


1,158(Increase) decrease in reserve for future Trust expenses


237,784


234,564


689,929


776,355General and administrative expenses


(237,804
)

(234,767
)

(690,097
)

(777,513
)Distributable income

$


$


$


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

$
.000000

$
.000000

$
.000000

$
.000000


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

1

---





STATEMENTS OF CHANGES IN TRUST CORPUS        (Unaudited)

Three Months Ended
September 30,

Nine Months Ended
September 30,2010

2009

2010

2009Trust corpus, beginning of period

$
24,611

$
29,969

$
27,186

$
31,338Distributable income











Distribution payable to Unit holders











Amortization of net overriding royalty interest


(1,242
)

(871
)

(3,817
)

(2,240
)Trust corpus, end of period

$
23,369

$
29,098

$
23,369

$
29,098


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

2

---





TEL OFFSHORE TRUST        NOTES TO FINANCIAL STATEMENTS        (Unaudited)

Note 1Trust Organization

Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of Dissolution ("Plan")
approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was formed in which the Trust owns a 99.99%
interest and Tenneco Oil Company initially owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest ("Royalty") equivalent to a 25% net profits interest
in the oil and gas properties (the "Royalty Properties") of Tenneco Exploration, Ltd. located offshore Louisiana to the Partnership and issuing certificates evidencing units of beneficial
interest in the Trust ("Units") in liquidation and cancellation of Tenneco Offshore's common stock.

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

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



3

---



TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1Trust Organization (Continued)

The
Trust is currently administered by The Bank of New York Mellon Trust Company, N.A. (the "Corporate Trustee"), which succeeded JPMorgan Chase Bank, N.A. as the corporate trustee,
effective October 2, 2006 pursuant to an agreement under which The Bank of New York acquired substantially all of the corporate trust business of JPMorgan Chase (formerly known as The Chase
Manhattan Bank), and Gary C. Evans, Jeffrey S. Swanson and Thomas H. Owen, Jr. (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.

4

---



TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2Basis of Accounting (Continued)

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 September 30, 2009 would substantially represent the revenues and
expenses from the Royalty Properties from May 2009 through July 2009. Similarly, any cash conveyed to the Trust from the Royalty during the quarter ended September 30, 2010 would substantially
represent the revenues and expenses from the Royalty Properties from May 2010 through July 2010. However, there was no cash conveyed to the Trust from the Royalty Properties from either May 2009
through July 2009 or May 2010 through July 2010. The financial and operating information included in this Form 10-Q for the three months ended September 30, 2010 and
September 30, 2009 represents financial and operating information with respect to the Royalty Properties for the immediately preceding months of May, June and July. Similarly, financial and
operating information with respect to the Royalty Properties for the nine months ended September 30, 2010 and September 30, 2009 represents financial and operating information with
respect to the Royalty Properties for the immediately preceding months of November through July. 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

5

---



TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2Basis of Accounting (Continued)

the
Special Cost Escrow account are not reflected in the financial statements of the Trust. However, funds deposited to or released from the Special Cost Escrow account are included in the Royalty
income.

The
preparation of financial statements requires the Trustees to make use of estimates and assumptions that affect amounts reported in the financial statements as well as certain
discounts. Actual results could differ from those estimates.

The
amount of cash distributions by the Trust is dependent on, among other things, the sales prices for oil and gas produced from the Royalty Properties and the quantities of oil and gas
sold. It should be noted that substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and
other actions taken by major petroleum producing nations, as well as the regional supply and demand for gas, weather, industrial growth, conservation measures, competition, economic conditions
generally and other variables. The Trust does not enter into any hedging transactions on future production.

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

Going Concern Uncertainty

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

Note 3Net Overriding Royalty Interest

The Royalty entitles the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance, dated January 1, 1983, provides that the
Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the Net Proceeds from their oil and
gas properties for the period. Generally, "Net Proceeds" means the amounts received by the Working Interest Owners from the sale of minerals from the Royalty Properties less operating and capital
costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and a Special Cost Escrow account. The
Special Cost Escrow account (See Note 5) is established for the future costs to be incurred to plug and abandon wells, 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

6

---



TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 3Net Overriding Royalty Interest (Continued)

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:Third

$
0Second


0First


02009:Fourth

$
0Third


0Second


0First


0


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

There
are not likely to be sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable
future. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue to be severely impacted by reduced production, from historical levels, and the amount of expenditures incurred
that are associated with such damages, including the expenditures required to plug and abandon the wells on Eugene Island 339 and to redevelop the facility at Eugene Island 339. While Chevron has
stated that it intends to redevelop Eugene Island 339, there is no obligation for Chevron to continue to pursue such

7

---



TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4Distributions to Unit Holders (Continued)

redevelopment.
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 $9.4 million of which had been incurred through September 30, 2010. If development and production costs of the Royalty Properties 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 of September 30, 2010, aggregate development and production costs for the Royalty Properties
since November 2008 have exceeded the related proceeds of production from the Royalty Properties by approximately $6.3 million. Significant development and production costs will continue to be
incurred if Eugene Island 339 is redeveloped. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this
time, the ultimate outcome of these matters cannot be determined with any degree of certainty.

Note 5Special Cost Escrow Account

The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for the reserve of funds for
estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling
projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on certain factors, including estimates of
aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net profits interest. Deposits into this account reduce current distributions and
are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest
generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated production costs. Special Cost Escrow funds will generally be utilized to pay Special Costs to the extent
there are not adequate current net profits interest to pay such costs. Special Costs that have been paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost
Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of
the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost
Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow account will also be released when the balance in such account
exceeds 125% of estimated future Special Costs. In the third quarter of 2010, there were no funds released or escrowed from the Special Cost Escrow account. As

8

---



TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 5Special Cost Escrow Account (Continued)

of
September 30, 2010, $4,306,846 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the financial statements of the Trust.

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

Note 6Reserve For Future Trust Expenses

The Trust generally maintains a cash reserve, equal to approximately three times the average annual expenses of the Trust during each of the then past three years, to provide for future
administrative expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the
Trust has not received sufficient Net Proceeds to maintain the reserve at such level. During the third quarter of 2010, the Trust used $237,784 from the reserve account for current expenses, leaving a
reserve balance as of September 30, 2010 of $573,151, or approximately 67% of the average annual expenses of the Trust during the three-year period ended September 30, 2010.
The reserve amount at December 31, 2009 was $1,263,080, or approximately 1.7 times the average annual expenses of the Trust during the three-year period ended December 31,
2009.

There
are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. Absent the receipt of Net Proceeds or other actions being taken, at some point in
2011, 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 cash reserves for payment of obligations of the Trust. As such, the Trustees may take certain actions, discussed below, on behalf of the Trust as permitted under
the Trust Agreement, which could materially impact the Unit holders.

Pursuant
to the terms of the Trust Agreement, the Trustees, on behalf of the Trust, 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

9

---



TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 6Reserve For Future Trust Expenses (Continued)

portion
of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the
Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

***********

10

---





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 September 30, 2010 and 2009

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

11

---



Crude
oil and condensate revenues increased $704,145, or 26%, to $3,420,889 in the third quarter of 2010 from $2,716,744 in the third quarter of 2009, due to increased realized prices.
Oil volumes during the third quarter of 2010 decreased 6% to 42,811 barrels, compared to 45,222 barrels of oil produced in the third quarter of 2009, due primarily to a 36-day
shut-in for pipeline repairs at Ship Shoal 182/183 during the second quarter of 2010. The average price received for crude oil and condensate increased 33%, or $19.83, to $79.91 per barrel
in the third quarter of 2010 from $60.08 per barrel in the third quarter of 2009.

Gas
revenues increased $207,311, or 654%, to $239,020 in the third quarter of 2010 from $31,709 in the third quarter of 2009, due primarily to increased production at Ship Shoal 182/183.
Gas volumes during the third quarter of 2010 increased 536% to 52,524 Mcf, compared to 8,255 Mcf produced in the third quarter of 2009. The average price received for natural gas was $4.55 per Mcf in
the third quarter of 2010 compared to $3.84 per Mcf in the third quarter of 2009. Gas products revenue increased $55,791, or 1,482%, to $59,555 in the third quarter of 2010 from $3,764 in the third
quarter of 2009 due primarily to increased production at Ship Shoal 182/183. Gas products volumes during the third quarter of 2010 increased 1,246% to 60,757 gallons, compared to 4,515 gallons in the
third quarter of 2009.

Capital
expenditures decreased by $287,730, or 61%, from $473,515 in the third quarter of 2009 to $185,785 in the third quarter of 2010. The higher amount of capital expenditures during
the third quarter of 2009 primarily relate to an oil tank replacement and a gas panel upgrade at Ship Shoal 182/183.

Operating
expenses decreased by $1,398,064, or 21%, from $8,192,655 in the third quarter of 2009 to $6,794,591 in the third quarter of 2010, due primarily to less well and platform
abandonment work
being conducted at Eugene Island 339 in the third quarter of 2010 as compared to the third quarter of 2009.

The
Royalty Properties had undistributed net loss of $3,582,155 in the third quarter of 2010.

In
the third quarter of 2010, there were no funds released or escrowed from the Special Cost Escrow account. As of September 30, 2010, $4,306,846 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 third quarter of 2009, there were no funds released or escrowed from the Special Cost Escrow account. As of September 30, 2009, $4,306,985 remained in the Special Cost
Escrow account.

Nine Months Ended September 30, 2010 and 2009

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

Crude
oil and condensate revenues increased $4,037,049, or 73%, to $9,576,368 in the first nine months of 2010 as compared to $5,539,319 for the same period in 2009, due primarily to
increased production at Ship Shoal 182/183 and increased realized prices. Oil volumes increased 25% to 123,586 barrels in the first nine months of 2010 from 99,207 barrels in the first nine months of
2009. The revenues and volumes for the first nine months of 2009 reflect credits associated with an audit for prior

12

---



periods
for $224,511 in revenues and 311 barrels. The average price received for crude oil and condensate increased 39%, or $21.65, to $77.49 per barrel in the first nine months of 2010 from $55.84
per barrel in the first nine months of 2009. Prior to taking into account such adjustments to revenues and volumes in the first nine months of 2009, the average price received for crude oil and
condensate would have been $53.74 per barrel in the first nine months of 2009.

Gas
revenues increased $181,618, or 21%, to $1,049,689 in the first nine months of 2010 from $868,071 for the same period in 2009, due primarily to increased production a Ship Shoal
182/1813. Gas volumes increased 49% to 209,345 Mcf in the first nine months of 2010 from 140,625 Mcf for the same period in 2009. The revenues and volumes for the first nine months of 2009 reflect net
credits of $808,484 in revenues and 127,711 Mcf of gas for prior adjustments. The average price received for natural gas decreased 19%, or $1.16, to $5.01 per Mcf in the first nine months of 2010 from
$6.17 per Mcf in the same period of 2009. Prior to taking into account such adjustments to revenues and volumes in the first nine months of 2009, the average price received for natural gas would have
been $4.61 per Mcf in the first nine months of 2009. Gas products revenue decreased $21,613, or 11%, to $177,777 in the first nine months of 2010 from $199,390 in the same period of 2009, due
primarily to an decrease in production volume of 24,522 gallons, or 14%, to 152,903 gallons in the first nine months of 2010 from 177,425 gallons in the same period of 2009.

Capital
expenditures decreased $479,125, or 63%, from $760,903 in the first nine months of 2009 to $281,778 in the same period of 2010. The higher amount of capital expenditures during
the first nine months of 2009 related primarily to repairs of damages caused by Hurricane Ike in September 2008. Reflected in the capital expenditures for the first nine months of 2009 is a refund of
$59,794 for certain prior period audit adjustments.

Operating
expenses decreased by $10,534,219, or 41%, from $25,482,586 in the first nine months of 2009 to $14,948,367 in the first nine months of 2010, due primarily to less well and
platform abandonment work being conducted at Eugene Island 339 in the first nine months of 2010 as compared to the first nine months of 2009. Reflected in the operating expenses for the first nine
months of 2009 are cost allocation refunds of an aggregate of $115,252 for certain prior period adjustments. Reflected within the operating expenses are management fees to Chevron, as Managing General
Partner of the Partnership, of $950,091 and $758,946 for the first nine months of 2009 and the first nine months of 2010, respectively.

The
Royalty Properties had undistributed net loss of $4,426,312 for the nine months ended September 30, 2010.

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

Reserve for Future Trust Expenses

In accordance with the provisions of the Trust Agreement, generally all Royalty income received by the Trust, net of Trust general and
administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. The Trust has previously
determined that a cash reserve equal to approximately three times the average annual expenses of the Trust during each of the then past three years was sufficient to provide for future administrative
expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the

13

---



Trust
has not received sufficient Net Proceeds to maintain the reserve at such level. During the third quarter of 2010, the Trust used $237,784 from the reserve for current expenses, leaving a reserve
balance as of September 30, 2010 of $573,151, or approximately 67% of the average annual expenses of the Trust during the three-year period ended September 30, 2010. The
reserve amount at December 31, 2009 was $1,263,080, or approximately 1.7 times the average annual expenses of the Trust during the three-year period ended December 31, 2009.
See "Liquidity and Capital Resources" for a discussion of certain potential alternatives available to the Trustees for obtaining cash for Trust expenses.

Other

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

Operational Review

The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike in September 2008. Crude oil revenues from
Eugene Island 339 represented approximately 48% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 47% of such revenues for the nine months ended
September 30, 2008. Eugene Island 339 contributed approximately 12% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 41% of such revenues for the
nine months ended September 30, 2008. Based on a prior year reserve study prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants, Eugene Island 339 accounted for
approximately 34% of the total future net revenues attributable to the Partnership's interest in the Royalty as of October 31, 2007. Chevron is working on the plugging and abandonment of the
existing wells, clearing debris and otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the second quarter of 2012. The Trust's net portion of
the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 is estimated to be approximately $13 million, approximately $9.4 million of which had been
incurred through September 30, 2010. Generally, if production ceases from an outer continental shelf lease, like that for Eugene Island 339, production must be restored or drilling operations
must commence within 180 days of the cessation of production (which was in early March 2009 with respect to Eugene Island 339 given the cessation of production in September 2008 resulting from
Hurricane Ike), or the lease will be terminated. Alternatively, an operator of a lease may seek a Suspension of Operations, or "SOP," that, if approved by the regional supervisor of the Bureau of
Ocean Energy Management, Regulation and Enforcement ("BOEM," formerly the Minerals Management Service), allows additional time to restore production in the event of certain circumstances, such as
hurricanes and other events beyond the control of the operator. Chevron, as the operator of Eugene Island 339, sought and obtained an SOP that provides for the redevelopment of Eugene Island 339 and
the adjacent lease, Eugene Island 338 (which is not a Royalty Property), as a single development project. The SOP extends the lease on Eugene Island 339 until November 30, 2010, as long as
certain milestones are met. Such milestones include the awarding of a front-engineering

14

---



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

15

---



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

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

Three Months Ended September 30, 2010 and 2009

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

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

Ship
Shoal 182/183 crude oil revenues increased from $2,638,386 in the third quarter of 2009 to $3,259,209 in the third quarter of 2010, due to an increase in the average crude oil price
received from $60.14 per barrel in the third quarter of 2009 to $80.15 per barrel for the same period in 2010. Net

16

---



crude
oil production decreased from 43,868 barrels in the third quarter of 2009 to 40,666 barrels in the third quarter of 2010. Gas revenues increased from $22,265 in the third quarter of 2009 to
$218,627 in the third quarter of 2010. Gas production increased from 5,759 Mcf in the third quarter of 2009 to 47,160 Mcf in the third quarter of 2010. The lack of gas production in the third quarter
of 2009 was due to the cessation of production in September 2008 resulting from damages inflicted by Hurricane Ike. Capital expenditures decreased from $473,116 in the third quarter of 2009 to
$154,983 in the third quarter of 2010. The higher amount of capital expenditures during the third quarter of 2009 primarily relate to an oil tank replacement and a gas panel upgrade. Operating
expenses increased from $611,048 in the third quarter of 2009 to $1,526,681 for the same period in 2010 due primarily to an unsuccessful well workover and continuing repair costs related to damages
inflicted by Hurricane Ike.

Eugene
Island 339 net crude oil revenues and volumes were $0 for the third quarter of 2010 and 2009. Gas revenues and volumes were $0 in the third quarter of 2010 and 2009. Capital
expenditures decreased from $367 in the third quarter of 2009 to $0 in the third quarter of 2010. Capital expenditures made during the third quarter of 2009 relate primarily to damages inflicted by
Hurricane Ike. Operating expenses decreased from $7,452,444 in the third quarter of 2009 to $5,259,967 in the third quarter of 2010, due primarily to less well and platform abandonment work being
conducted in the third quarter of 2010 as compared to the third quarter of 2009.

West
Cameron 643 gas revenues were $0 in the third quarter of 2009 and in the third quarter of 2010. Gas volumes were 0 Mcf in the third quarter of 2009 and 2010 as a result of the field
being shut-in following Hurricane Ike in September 2008. Operating expenses decreased from $121,969 in the third quarter of 2009 to $13,391 for the same period in 2010. Capital
expenditures decreased from $7,884 in the third quarter of 2009 to $0 for the same period in 2010.

South
Timbalier 37/27 crude oil revenues increased from $78,257 in the third quarter of 2009 to $89,497 for the same period in 2010 due primarily to an increase in realized oil prices.
There was a decrease in crude oil production volumes to 1,124 barrels in the third quarter of 2010 from 1,350 barrels in the third quarter of 2009. The average crude oil price received increased from
$57.95 per barrel in the third quarter of 2009 to $79.65 per barrel in the third quarter of 2010. Gas revenues
increased from $8,838 in the third quarter 2009 to $12,274 in the third quarter of 2010 due primarily to an increase in gas production and an increase in realized gas prices. There was an increase in
natural gas volumes from 2,370 Mcf in the third quarter of 2009 to 2,816 Mcf in the third quarter of 2010. The average natural gas price received increased from $3.73 per Mcf in the third quarter of
2009 to $4.36 per Mcf in the third quarter of 2010. Capital expenditures increased from $32 in the third quarter of 2009 to $30,802 in the third quarter of 2010, due primarily to well workovers.
Operating expenses increased from $7,193 in the third quarter of 2009 to $7,942 in the third quarter of 2010.

17

---



Nine Months Ended September 30, 2010 and 2009

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

Ship
Shoal 182/183 crude oil revenues increased from $5,111,927 in the first nine months of 2009 to $9,226,960 in the same period in 2010, due to an increase in net crude oil production
from 95,057 barrels in the first nine months of 2009 to 118,950 in the same period of 2010, and an increase in the average crude oil price from $53.78 per barrel in the first nine months of 2009 to
$77.57 per barrel for the same period in 2010. Gas revenues increased from $747,985 in the first nine months of 2009 to $1,006,631 in the same period of 2010. Gas production increased from 5,759 Mcf
in the first nine months of 2009 to 199,539 Mcf in the same period of 2010. However, there was an audit adjustment made in the first quarter of 2009, which resulted in the recognition of $725,720 in
gas revenues associated with 107,416 Mcf of gas from a prior period. The natural gas sales price was $3.87 per Mcf in the first nine months of 2009, excluding the audit adjustment made during 2009,
compared to $5.04 per Mcf in the first nine months of 2010. Capital expenditures decreased from $500,559 in the first nine months of 2009 to $243,438 in the same period of 2010. The higher capital
expenditures during the first nine months of 2009 primarily relate to an oil tank replacement and a gas panel upgrade. Operating expenses increased from $2,009,644 in the first nine months of 2009 to
$3,045,054 for the same period in 2010 due primarily to an unsuccessful well workover during the third quarter of 2010 and continuing repair costs related to damages inflicted by Hurricane Ike.

Eugene
Island 339 net crude oil revenues decreased from $38,544 in the first nine months of 2009 to $0 for the same period in 2010, due to a decrease in volumes from 318 barrels in the
first nine months of 2009 to 0 barrels in the first nine months of 2010. However, there was no actual crude oil production during the first nine months of 2009 and such crude oil revenues and
production volumes are entirely from an audit adjustment made in the first quarter of 2009 and associated with a prior period. Gas revenues decreased from $170,231 in the first nine months 2009 to $0
for the same period
in 2010, due to a decrease in natural gas volumes from 33,296 Mcf in the first nine months of 2009 to 0 Mcf for the same period in 2010. However, there was no actual gas production during the first
nine months of 2009 and such gas revenues and volumes are entirely from an audit adjustment made in the first quarter of 2009 and associated with a prior period. Capital expenditures decreased from
$180,456 in the first nine months of 2009 to $(8,582) in the same period in 2010. The higher capital expenditures during the first nine months of 2009 reflect costs associated with damages caused by
Hurricane Ike. Capital expenditures for the first nine months of 2010 reflect credits of $8,582 associated with the workover of a well during a prior period and an invoice correction related to well
abandonment. Operating expenses decreased from $21,672,896 in the first nine months of 2009 to $10,944,143 in the same period in 2010, due primarily to less well and platform abandonment work being
conducted in the first nine months of 2010 as compared to the first nine months of 2009.

West
Cameron 643 gas revenues increased from ($87,518) in the first nine months of 2009 to $5,244 for the same period in 2010. Gas volumes increased from (13,001) Mcf in the first nine
months of 2009 to 0 Mcf for the same period in 2010. There was no actual gas production during the first nine months of 2009 and 2010 as a result of the field being shut-in following
Hurricane Ike in September 2008. The revenues and volumes for the first nine months of 2009 are a result of debits to correct an error in revenue allocation in August 2008. The positive revenues for
the first nine months of 2010 are the result of a correction to a prior period audit adjustment made in the first quarter of 2009. Operating expenses decreased from $862,299 for the first nine months
of 2009 to $173,152 for the same

18

---



period
in 2010, and capital expenditures were $135,291 for the first nine months of 2009 and $0 for the first nine months of 2010, as the field was shut-in after Hurricane Ike in September
2008 as a result of damages to a third-party transporter's pipeline.

South
Timbalier 37/27 crude oil revenues increased from $194,278 in the first nine months of 2009 to $256,874 for the same period in 2010 due primarily to an increase in the average
crude oil price received from $51.69 per barrel in the first nine months of 2009 to $77.08 per barrel for the same period in 2010. There was a decrease in crude oil production volumes to 3,333 barrels
in the first nine months of 2010 from 3,759 barrels in the first nine months of 2009. Gas revenues increased from $32,179 in the first nine months of 2009 to $34,207 in the first nine months of 2010
due primarily to an increase in natural gas volumes from 6,416 Mcf in the first nine months of 2009 to 7,114 Mcf in the first nine months of 2010. The natural gas sales price was $5.02 per Mcf in the
first nine months of 2009 compared to $4.81 per Mcf in the first nine months of 2010. Capital expenditures increased from $(55,403) in the first nine months of 2009 to $46,921 in the first nine months
of 2010 after taking into account a $56,263 credit in 2009 for a prior period audit adjustment. The capital expenditures during the first nine months of 2010 relate primarily to well workovers.
Operating expenses increased from $(12,105) in the first nine months of 2009 to $27,070 in the first nine months of 2010 after taking into account a $36,992 credit in 2009 for a prior period audit
adjustment.

Liquidity and Capital Resources

The Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. Total
future net revenues attributable to the Partnership's interest in the Royalty were estimated at $13.1 million as of October 31, 2009. However, there are not likely to be sufficient Net
Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable future. On October 7, 2008, the Trust announced that
production from the two most significant oil and gas properties associated with the Trust had ceased following damage inflicted by Hurricane Ike in September 2008. The Trust has not received a
distribution of Net Proceeds since December 2008. Consequently, the Trust has not made a distribution to Unit holders for seven consecutive quarters, or since January 9, 2009. On
September 23, 2010, the Trust announced there would be no trust distributions for the third 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 to redevelop the facility at Eugene Island 339. While Chevron has stated that it intends to redevelop Eugene Island 339, there is no obligation for Chevron
to continue to pursue such redevelopment. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future.

The
platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike. Chevron is working on the plugging and abandonment of the existing wells, clearing debris and
otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the second quarter of 2012. Chevron has informed the Corporate Trustee that Chevron
presently intends to pursue the redevelopment of platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the BOEM in response to Chevron's submission to the
BOEM of a program to restore production at Eugene Island 339; however, there is no obligation for Chevron to pursue such redevelopment. The costs for such a redevelopment would be significant. Failure
or

19

---



inability
to pursue such a redevelopment, and on the timeframes approved by the BOEM, could result in a loss of the lease. At this time, there can be no assurance that production will be restored at
Eugene Island 339. See "Operations" for a more detailed discussion of Eugene Island 339.

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

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

Future
Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the
operators of the Royalty Properties. The Trust's net portion of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 is estimated to be approximately
$13 million, approximately $9.4 million of which had been incurred through September 30, 2010. If development and production costs of the Royalty Properties 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 of September 30, 2010, aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of production from the
Royalty Properties by approximately $6.3 million. Significant development and production costs will continue to be incurred if 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."

20

---



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 September 30, 2010 was $573,151, or approximately 67% of the average annual expenses of the Trust during the three-year period ended
September 30, 2010. The reserve amount at December 31, 2009 was $1,263,080, or approximately 1.7 times the average annual expenses of the Trust during the three-year period
ended December 31, 2009. As described herein, there are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. Absent the receipt of Net Proceeds or
other actions being taken, at some point in 2011, 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 cash reserves for payment of obligations of the Trust. As such, the Trustees may take certain actions, discussed below, on
behalf of the Trust as permitted under the Trust Agreement, which could materially impact the Unit holders.

Pursuant
to the terms of the Trust Agreement, the Trustees, on behalf of the Trust, 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.

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

21

---





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
$9.4 million of which had been incurred through September 30, 2010. Because the Trust will terminate in the event estimated future net revenues fall below $2.0 million, it would
be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination of the Trust, the Trustees will sell for cash
all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied. The estimates of future net revenues
discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties present in estimating future net revenues for the Royalty
Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed by DeGolyer and MacNaughton. In
addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth above is qualified in its
entirety by reference to the Trust's Annual Report on Form 10-K for the year ended December 31, 2009. The Trust's Form 10-K is available at the website of
the Securities and Exchange Commission ("SEC") atwww.sec.govor upon request from the Corporate Trustee.

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

22

---



Cost
Escrow account will also be released when the balance in such account exceeds 125% of estimated future Special Costs. In the third quarter of 2010, there were no funds released or escrowed from
the Special Cost Escrow account. As of September 30, 2010, $4,306,846 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 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
September 30,(1)2010

2009Crude oil and condensate (bbls)


42,811


45,222Natural gas and gas products (Mcfe)


61,204


8,900Crude oil and condensate average price, per bbl

$
79.91

$
60.08Natural gas average price, per Mcf (excluding gas products)

$
4.55

$
3.84Crude oil and condensate revenues

$
3,420,889

$
2,716,744Natural gas and gas products revenues


298,575


35,473Production expenses


(7,115,834
)

(8,535,496
)Capital expenditures


(185,785
)

(473,516
)Undistributed net loss (income)(2)


(3,573,884
)

6,247,115Refund of (provision for) Special Cost Escrow


(8,271
)

9,680Net Proceeds





Royalty interest


x25
%

x25
%Partnership share





Trust interest


x99.99
%

x99.99
%Trust share of Royalty income

$


$



---

23

---



Royalty Properties
Nine Months Ended
September 30,2010

2009Crude oil and condensate (bbls)


123,586


99,221Natural gas and gas products (Mcfe)


231,188


165,971Crude oil and condensate average price, per bbl

$
77.49

$
55.83Natural gas average price, per Mcf (excluding gas products)

$
5.31

$
6.43Crude oil and condensate revenues

$
9,576,368

$
5,539,319Natural gas and gas products revenues


1,227,465


1,067,461Production expenses


(14,948,367
)

(25,482,586
)Capital expenditures


(281,778
)

(760,904
)Undistributed net loss (income)(1)


4,417,280


19,538,783Refund of (provision for) Special Cost Escrow


9,032


97,927Net Proceeds





Royalty interest


x25
%

x25
%Partnership share





Trust interest


x99.99
%

x99.99
%Trust share of Royalty Income

$


$



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


Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

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

The
Trust may borrow money to pay expenses of the Trust. Additionally, if development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties,
the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess

24

---



costs
plus accrued interest, at a rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a
quarterly period in which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. Consequently, the Trust will be exposed to
interest rate market risk should it
borrow money to pay expenses and to the extent that development and production costs of the Royalty exceed the proceeds 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 of September 30, 2010, aggregate development and production costs for the Royalty Properties since November
2008 have exceeded the related proceeds of production from the Royalty Properties by approximately $6.3 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 September 30, 2010, there has been no change in
the
Trust's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. The Corporate
Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of the Working Interest Owners or the
Managing General Partner of the Partnership.

25

---





PART IIOTHER INFORMATION

Item 1A.    Risk Factors.

The Trust continues to utilize its cash 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 in 2011, the Trust will not have sufficient funds to pay the liabilities of the Trust. As such, the Trustees may take certain
actions on behalf of the Trust 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 its cash reserves to pay expenses; however, as of September 30, 2010, those reserves were approximately 67% of the average annual expenses of the Trust during the three-year
period ended September 30, 2010. Absent the
receipt of Net Proceeds, or other actions being taken, at some point in 2011, 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 on behalf of the Trust that could materially impact the Unit holders. Such actions include borrowing money, selling all or a part of the Trust's interest in the Partnership, exercising
their rights to dissolve the Partnership or causing a sale by the Partnership of the Royalty owned by the Partnership. See "Management's Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital Resources" under Item 2 of this Form 10-Q.

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

On April 22, 2010, a deepwater U.S. Gulf of Mexico drilling rig, theDeepwater
Horizon, sank after a blowout and fire at the Macondo wellsite. In response to such incident, the BOEM issued Notices to Lessees, or "NTLs," implementing additional safety and
certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, imposed additional requirements with respect to development and production activities in the U.S. Gulf of
Mexico and has delayed the approval of applications to drill in both deep-water and shallow-water areas.

To
the extent this incident results in federal legislation, policy, restrictions, or regulations that cause delays or deter new drilling in the U.S. Gulf of Mexico, or that increase the
costs of offshore production, the Royalty income payable to the Trust could be materially adversely affected. We cannot predict at this time the impact, if any, that this incident may have on the
operations of the Royalty Properties, particularly a redevelopment of Eugene Island 339, the Royalty income payable to the Trust or on the financial condition of the Trust. However, drilling activity
associated with the redevelopment of Eugene Island 339 has been suspended and the drilling rig moved off location pending the approval of drilling permits under the new guidelines issued by the BOEM
on June 8, 2010 pursuant to NTL No. 2010-N05, "Increased Safety Measures for Energy Development on the OCS".

26

---



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)


27

---



SEC File or
Registration
Number

Exhibit
Number10
(d)*


Gas Purchase and Sales Agreement Effective September 1, 1993 between Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company (Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of
TEL Offshore Trust)

0-06910

10(d)31



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



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


28

---





SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

TEL OFFSHORE TRUSTBy:

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

/s/ MIKE ULRICH Mike UlrichVice President


Date:
November 15, 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.

---



QuickLinks