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, 2013Oro

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


Commission File Number: 0-06910



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

Texas(State or other jurisdiction of
incorporation or organization)

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

78701(Zip Code)


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

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

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

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

Large accelerated filer o

Accelerated filer o

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

Smaller reporting company o


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

As of May 13, 2013, 4,751,510 Units of Beneficial Interest in TEL Offshore Trust were outstanding.





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NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (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, including without limitation, statements under "Trustee's Discussion and Analysis of Financial Condition and Results of Operations" in
Item 2 of Part I and elsewhere herein regarding the financial position, production and reserve growth, and other plans and objectives are forward-looking statements. Forward-looking
statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "could," "may," "should," "intend" or other words that convey the uncertainty
of future events or outcomes. These forward-looking statements are based on current expectations and assumptions about future events. 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 are disclosed in the risk
factors discussed in Item 1A of Part I of the Trust's Annual Report on Form 10-K for the year ended December 31, 2012 (the "2012 10-K") and such
other factors as may be set forth from time to time in the Trust's filings with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to the
Managing General Partner or the Trust or persons acting on behalf of the Managing General Partner or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no
obligation, and disclaims any duty, to update these forward-looking statements.

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PART IFINANCIAL INFORMATION

Item 1.    Condensed Financial Statements. (Unaudited)

TEL OFFSHORE TRUST  CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

March 31,
2013

December 31,
2012AssetsCash and cash equivalents

$
47,565

$
223,925Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,251,445 and $28,250,347, respectively


16,210


17,308Total assets

$
63,775

$
241,233Liabilities and Trust CorpusDistribution payable to Unit holders

$


$
Reserve for future Trust expenses


47,565


223,925Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)


16,210


17,308Total liabilities and Trust corpus

$
63,775

$
241,233


CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME

Three Months Ended
March 31,2013

2012Royalty income

$


$
Interest income


5


235


23Decrease in reserve for future Trust expenses


176,360


165,663General and administrative expenses


(176,365
)

(165,686
)Distributable income





Distributable income per Unit (basic and diluted (4,751,510 Units))

$
.000000

$
.000000Distributions per Unit (4,751,510 Units)

$
.000000

$
.000000


CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS

Three Months
Ended March 31,2013

2012Trust corpus, beginning of period

$
17,308

$
19,508Distributable income





Distribution payable to Unit holders





Amortization of net overriding royalty interest


(1,098
)

(734
)Trust corpus, end of period

$
16,210

$
18,774




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

1

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TEL OFFSHORE TRUST        NOTES TO CONDENSED FINANCIAL STATEMENTS

(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 (as amended, the "Trust Agreement"), provide, among other things, that:



2

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(1) Trust Organization (Continued)

On
October 27, 2011, the Partnership sold 20% of the Royalty for gross proceeds of $1,600,000. See Note 3.

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, Thomas H. Owen, Jr., and Jeffrey S. Swanson (the "Individual Trustees"), as trustees (the "Trustees").

(2) Basis of Accounting and Going Concern

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 ("GAAP"). 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, 2012.

Overriding Royalty InterestThe Trust uses the modified cash basis of accounting to report Trust receipts from the overriding royalty and payments of
expenses incurred. The actual cash distributions to the Trust are made based on the terms of the conveyance that created the Trust's overriding royalty interest. The overriding royalty interest
entitles the Trust to receive revenues (oil, gas and natural gas liquid sales) less expenses (the amount by which all royalties, lease operating expenses including well workover costs, production and
property taxes, post-production costs including plugging and abandonment, and producing overhead of the underlying properties) multiplied by 20%. Actual cash receipts may vary due to
timing delays of cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices.

Modified Cash Basis of AccountingThe condensed financial statements of the Trust, as
prepared on a modified cash basis, reflect the Trust's assets, liabilities, Trust corpus, earnings and distributions, as follows:



3

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(2) Basis of Accounting and Going Concern (Continued)



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 condensed financial statements of the Trust differ from condensed financial statements prepared in accordance with GAAP, 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. This comprehensive basis of accounting other than GAAP
corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E,Financial
Statements of Royalty Trusts.

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 any of the
Working Interest Owners.

On
the last business day of each calendar quarter prior to August 1, 2011, the Working Interest Owners were to pay to the Partnership 25% of the Net Proceeds (as defined below in
Note 3) for the immediately preceding Quarterly Period. As discussed in Note 3Net Overriding Royalty Interest, on October 27, 2011, but effective as of
August 1, 2011, the Partnership sold 20% of the Royalty to a third party; as a result, on the last business day of each calendar quarter after August 1, 2011, the Working Interest Owners
are to pay to the Partnership 20% 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, if any, are made in January,
April, July and October of each year, and are payable to Unit holders of record as of the last business day of each calendar quarter. Thus, any cash conveyed to the Trust from the Royalty during the
quarter ended March 31, 2013 would substantially represent the revenues and expenses from the Royalty Properties from November 2012 through January 2013. Similarly, any cash conveyed to the

4

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(2) Basis of Accounting and Going Concern (Continued)

Trust
from the Royalty during the quarter ended March 31, 2012 would substantially represent the revenues and expenses from the Royalty Properties from November 2011 through January 2012.
However, there was no cash conveyed to the Trust from the Royalty Properties from either November 2012 through January 2013 or November 2011 through January 2012. The financial and operating
information included in this Form 10-Q for the three months ended March 31, 2013 and
March 31, 2012 represents financial and operating information with respect to the Royalty Properties for the immediately preceding months of November, December and January. Income from the
Royalty is recorded by the Trust on a cash basis, when it is received by the Trust from the Partnership.

Amortization of Overriding Royalty InterestThe Trust amortizes the investment in overriding royalty interest using the
units-of-production method. The Trust's rate of recording amortization is dependent upon the estimates of total proved reserves, which incorporates various assumptions and
future projections. If the estimates of total proved reserves decline significantly, the rate at which the Trust records amortization expense would increase, reducing Trust corpus. Such a decline in
reserves may result from lower commodity prices, which may make it uneconomic to produce from higher cost fields. The Trust is unable to predict changes in reserve quantity estimates as such
quantities are dependent on future economic and operational conditions.

Impairment of Investment in Overriding Royalty InterestThe Trust reviews overriding royalty interests in oil and gas properties for possible
impairment whenever events or circumstances indicate the carrying amount of the asset may not be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash
flows (undiscounted and without interest charges) expected to result from the use of the asset and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an
impairment loss is recognized to write down the asset to its estimated fair value. Preparation of estimated expected future cash flows is inherently subjective and is based on the Corporate Trustee's
best estimate of assumptions concerning expected future conditions. There were no write downs taken in the three months ended March 31, 2013.

Cash and Cash EquivalentsCash and cash equivalents include all highly liquid short-term investments with original maturities of three
months or less.

Reserve for future Trust expensesRepresents cash reserves for future Trust expenses established by the Trustee. The changes in reserves for future
Trust expenses includes both changes of amounts deemed necessary by the Trustees and related distributions, as well as amounts paid from the reserve during periods when the Trust has insufficient
income to pay Trust expenses. See Note 6.

Proceeds from Sale of Overriding RoyaltyThe Trust records proceeds from the sale of Overriding Royalty Interests when received.

Special Cost Escrow accountThe Special Cost Escrow account (see Note 5) is established for 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

5

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(2) Basis of Accounting and Going Concern (Continued)

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

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

Recent Accounting PronouncementsThere were no accounting pronouncements issued during the three months ended March 31, 2013, applicable to the
Trust or its condensed financial statements.

Going ConcernThe accompanying condensed financial statements have been prepared assuming that the Trust will continue as a going concern. Financial
statements prepared on the going concern basis assume the realization of assets and the settlement of liabilities in the normal course of
business. The Trust has not received royalty income since the fourth quarter of 2008. The lack of sufficient Net Proceeds to make distributions in the foreseeable future as discussed in Note 4
and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going concern. Certain potential alternatives available to the Trustees are
described in Note 6. The condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty.

(3) Net Overriding Royalty Interest

On October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale of 20% of the Royalty. The sale generated $1,600,000 in gross
proceeds and occurred as part of a formal auction process for the Royalty. The Trust received from the Partnership a distribution of approximately $1,485,851, representing 99.99% of the net proceeds
from the sale of $1,486,000. The Trust has used, and will continue to use such net proceeds solely for the payment of expenses of the Trust.

The
sale is governed by a letter agreement, pursuant to which the Partnership and RNR Production, Land and Cattle Company, Inc. ("RNR Production") made various representations and
warranties, with related indemnification obligations. In connection therewith, the Partnership and RNR Production executed a Partial Assignment of Overriding Royalty Interests.

The
sale was made to RNR Production on October 27, 2011, though the assignment of the 20% was effective as of August 1, 2011. Pursuant to an Option Agreement, the
Partnership agreed with RNR Production that if the Partnership elected to sell, or market for sale, any portion of the Royalty on or prior to December 31, 2012, RNR Production would have the
option to acquire such percentage
interest, up to an additional 5% of the entire Royalty, for a sales price equivalent to the product of $80,000 times the percentage interest acquired.

6

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(3) Net Overriding Royalty Interest (Continued)

On
July 11, 2012, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the
Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell a portion of the Royalty so that the Trust will have sufficient funds to pay its liabilities. The
Trustees initiated contact with RNR Production to determine its interest in purchasing the additional five percent (5%) of the Royalty pursuant to an Option Agreement entered into between the
Partnership and RNR Production in connection with the Partnership's previous sale of 20% of the Royalty to RNR Production. In addition, and pursuant to the Option Agreement, Chevron, as the Managing
General Partner of the Partnership, provided RNR Production with formal notice that the Partnership would be marketing additional Royalty interests and that RNR Production must exercise its option to
purchase the additional Royalty within ten days of the receipt of such notice. RNR Production indicated that it was not interested in purchasing an additional part of the Royalty pursuant to the
Option Agreement and its right to purchase under the Option Agreement expired on December 31, 2012.

The
Royalty entitles the Trust to its share (99.99%) of 80% 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 the Special Cost Escrow account. The
Special Cost Escrow account 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.

As
of October 9, 2001, Chevron Corporation merged with Texaco Inc. and the Royalty Properties owned by Texaco Exploration and Production Inc. ("TEPI") were assigned
to Chevron U.S.A. Inc. ("Chevron") on May 1, 2002. Crude oil sales from the Chevron and TEPI properties added together accounted for 100% of crude oil revenues from the Royalty
Properties for the three months ended March 31, 2013
and March 31, 2012. Sales to Chevron Corporation accounted for 100% of total gas revenues from the Royalty Properties for the three months ended March 31, 2013 and March 31, 2012.

The
Trust's share of Royalty income was reduced by approximately $39,722 and $69,908, respectively, for each of the three months ended March 31, 2013 and March 31, 2012,
respectively, for management fees paid to the Working Interest Owners as reimbursement for expenses incurred by them on behalf of the Trust. Such management fees were calculated as 3% of the Trust's
share of the sum of revenues, production expenses and capital expenditures attributable to the Royalty Properties in each of the periods above.

7

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(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. These 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.

Production
ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. 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. On December 19, 2008, the Trust announced its fourth quarter
distribution of approximately $0.7 million, which was paid on January 9, 2009. The funds available for the fourth quarter distribution were severely negatively impacted by Hurricane Ike.
On March 25, 2009, the Trust announced that there would be no trust distribution for the first quarter of 2009, and the Trust has not made a distribution since January 9, 2009. In the
fourth quarter of 2010, Chevron withdrew $4,304,894 from the Special Cost Escrow account of the Working Interest Owners to cover expenses incurred in connection with the plugging and abandonment of
Eugene Island 339, which served to reduce the amount by which development and production costs exceeded the related proceeds of production as of December 31, 2010; however, additional deposits
to the Special Cost Escrow account would be required in future periods in accordance with the terms of the Conveyance if, and when, Net Proceeds would otherwise be payable on the Royalty.

While
oil and gas production at Ship Shoal 182 and 183 and at Eugene Island 339 has been partially restored, 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. There can be no assurance by Chevron or anyone else as to the actual timing for any future distributions to the Partnership from the Royalty,
and there is no guarantee that any further distributions will be made. 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. In September 2012, Chevron informed the Trust that the estimate of the Royalty's net portion of the
aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $18.7 million to approximately $19.8 million. In March 2013,
Chevron informed the Trust that of the estimated $19.8 million, approximately $19.76 million of which had been incurred through January 31, 2013. 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 October 31, 2012, aggregate
development and production costs for the Royalty Properties since November 2008 have

8

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(4) Distributions to Unit Holders (Continued)

exceeded
the related proceeds of production from the Royalty Properties by approximately $7.9 million, net to the entire Royalty ($6.3 million applicable to the Trust as of
December 31, 2012). The $7.9 million amount (and the $6.3 million applicable to the Trust) reflects adjustments in 2012, including an insurance credit of approximately $381,000
received by Chevron and allocated for the benefit of the
Royalty with respect to Eugene Island 339 in 2012. The excess development and production costs have decreased from $7.9 million to $6.9 million (or $5.5 million, net to the
Trust's remaining 20% royalty interest) as of January 31, 2013, reflecting increased production from the Royalty Properties and the benefit of an audit adjustment of Eugene Island 339.

For
the three months ended March 31, 2013, the Trust had undistributed net income of $740,770 representing the Trust's portion of the aggregate undistributed net income of
$3,703,850. Included within the aggregate undistributed net income is an audit adjustment of Eugene Island 339 which resulted in additional proceeds of $1,869,919 ($373,984 net to the Trust). This
brings the Trust's share of the accumulated undistributed net loss to $5,552,557, representing the Trust's portion of the aggregate undistributed net loss associated with the Royalty Properties
through the period ended March 31, 2013. 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.

(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 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 certain 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. As of March 31, 2013, approximately $1,000 remained in the Special Cost Escrow account. Special Cost Escrow account 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

9

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(5) Special Cost Escrow Account (Continued)

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 future Special Costs.

During
the first quarter of 2013 and during 2012, there were no funds released from or deposited into the Special Cost Escrow account.

In
connection with the sale of 20% of the Royalty by the Partnership in October 2011, the Partnership also assigned 20% of its rights and obligations with respect to the Special Cost
Escrow.

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.

Deposits
to the Special Cost Escrow Account will 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.

(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 first quarter of 2013, the Trust decreased its reserve by $176,360, to pay current expenses, resulting
in a reserve balance of $47,565 as of March 31, 2013, or approximately 6% of the average annual expenses of the Trust during the three-year period ended March 31, 2013. As of
December 31, 2012, the reserve was $223,925 or 27% of the average annual expenses during the three year period ended December 31, 2012.

There
are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. There can be no assurance by Chevron or anyone else as to the actual timing for
any future distributions to the Partnership from the Royalty, and there is no guarantee that any further distributions will be made. Absent the receipt of Net Proceeds or other actions being taken, it
is anticipated that by the end of the second quarter of 2013, the Trust will not have sufficient funds to pay the liabilities 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 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

10

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(6) Reserve For Future Trust Expenses (Continued)

liabilities
of the Trust, no distributions will be made to the Unit holders until the indebtedness created by such borrowings has been paid in full.

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.

On
March 11, 2011, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the
Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell such portion, and only such portion, of the Royalty that will provide the Trust with a current
distribution equal to $2,000,000 from the proceeds of such sale.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale of 20% of the Royalty to RNR Production, which generated $1,600,000
in gross proceeds and occurred as part of such formal auction process for the Royalty. The Trust received from the Partnership a distribution of approximately $1,485,851, representing 99.99% of the
net proceeds from the sale of $1,486,000. The Trust has used and will continue to use such net proceeds solely for the payment of expenses of the Trust.

The
sale was made to RNR Production on October 27, 2011, though the assignment is effective as of August 1, 2011. Pursuant to an Option Agreement, the Partnership agreed
with RNR Production that if the Partnership elected to sell, or market for sale, any portion of the Royalty on or prior to December 31, 2012, then RNR Production would have the option to
acquire such percentage interests, up to an additional 5% of the entire Royalty, for a sales price equivalent to the product of $80,000 time the percentage interest acquired.

On
July 11, 2012, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the
Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell a portion of the Royalty so that the Trust will have sufficient funds to pay its liabilities. The
Trustees initiated contact
with RNR Production to determine its interest in purchasing the additional five percent (5%) of the Royalty pursuant to an Option Agreement entered into between the Partnership and RNR Production in
connection with the Partnership's previous sale of 20% of the Royalty to RNR Production. In addition, and pursuant to the Option Agreement, Chevron, as the Managing General Partner of the Partnership,
provided RNR Production with formal notice that the Partnership would be marketing additional Royalty interests and that RNR Production must exercise its option to purchase the additional Royalty
within ten days of the receipt of such notice. RNR Production indicated that it was not interested in purchasing an additional part of the Royalty pursuant to the Option Agreement and its right to
purchase under the Option Agreement expired on December 31, 2012.

11

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(6) Reserve For Future Trust Expenses (Continued)

In
September 2012, the Trustees unanimously determined to suspend future payments of fees to the Trustees effective as of the third quarter of 2012, until a date to be determined in the
future by the Trustees. Such suspended fees will be accrued as an expense of the Trust, but will not be paid currently.

On
October 16, 2012, the Trustees provided written notice to Chevron to proceed with an alternative sale process to sell such portion, and only such portion, of the Royalty that
will provide the Trust with a current distribution equal to $1,000,000 from the proceeds of such sale. Based on a recommendation from Chevron, as the Managing General Partner of the Partnership,
Chevron marketed for sale by the Partnership the entire Royalty; however, the Trust reserved the right to sell only a portion of the Royalty. Also based on a recommendation from Chevron, Chevron
engaged EnergyNet.com to conduct the marketing process and related auction of the Royalty. In December 2012 following the due date for any bids for the purchase of the Royalty, the Trustees elected to
delay any further action with respect to the proposed sale by the Partnership of the Royalty. Accordingly, the Trustees instructed Chevron to delay any further action regarding a potential sale and
the Trustees are continuing to evaluate the alternatives available to the Trust.

(7) Federal Income Tax Matters

The IRS has ruled that the Trust is a grantor trust and that the Partnership is a partnership for federal income tax purposes. Thus, the Trust will incur no federal income tax liability
and each Unit holder will be treated as owning an interest in the Partnership.

(8) Commitments and Contingencies

The Managing General Partner of the Partnership has advised the Trust that, although Chevron believes that it is in general compliance with applicable health, safety and environmental
laws and regulations that have taken effect at the federal, state and local levels, costs may be incurred to comply with current and proposed environmental legislation that could result in increased
operating expenses on the Royalty Properties.

(9) Subsequent Events

On April 9, 2013, the Trust issued a press release announcing that there would be no trust distribution for the first quarter of 2013 for Trust unitholders of record on
March 31, 2013.

12

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Item 2.    Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

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 $14.5 million as of October 31, 2012. However, as discussed below, as a result of damage
inflicted by Hurricane Ike in 2008, 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. The Trust has not received a distribution of Net Proceeds since December 2008. Because of the lack of Net Proceeds, the Trust has in the past not had sufficient cash flow
to pay expenses on a current basis, and the Trust may in the future not have sufficient cash flow to pay expenses on a current basis. There can be no assurance by Chevron or anyone else as to the
actual timing for any future distributions to the Partnership from the Royalty, and there is no guarantee that any further distributions will be made.

The
Trust Agreement 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.

In
addition, 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 distributions
will be made to the Unit holders until the indebtedness created by such borrowings has been paid in full.

On
March 11, 2011, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the
Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell such portion, and only such portion, of the Royalty that would provide the Trust with a current
distribution equal to $2,000,000 from the proceeds of such sale.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale of 20% of the Royalty to RNR Production. The sale generated
$1,600,000 in gross proceeds and occurred as part of a formal auction process for the Royalty. The Trust received from the Partnership a distribution of approximately $1,485,851, representing 99.99%
of the net proceeds from the sale of $1,486,000. The Trust has used and will continue to use such net proceeds solely for the payment of expenses of the Trust.

The
sale was made to RNR Production on October 27, 2011, though the assignment is effective as of August 1, 2011. Pursuant to an Option Agreement entered into at the time
of the sale, the Partnership agreed with RNR Production that if the Partnership elected to sell, or market for sale, any portion of the Royalty on or prior to December 31, 2012, then RNR
Production would have the option to acquire such percentage interests, up to an additional 5% of the entire Royalty, for a sales price equivalent to the product of $80,000 time the percentage interest
acquired. RNR Production's right to purchase under the Option Agreement expired on December 31, 2012.

13

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In
September 2012, the Trustees unanimously determined to suspend future payments of fees to the Trustees effective as of the third quarter of 2012, until a date to be determined in the
future by the Trustees. Such suspended fees will be accrued as an expense of the Trust, but will not be paid currently.

Based
on the continuing expenses of the Trust and the lack of any distributions and any assurances as to the actual timing of any future distributions, on July 11, 2012, the
Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the Trustees therefore instructed Chevron, as the
Managing General Partner of the Partnership, to sell a portion of the Royalty so that the Trust will have sufficient funds to pay its liabilities. The Trustees initiated contact with RNR Production to
determine its interest in purchasing the additional five percent (5%) of the Royalty pursuant to an Option Agreement entered into between the Partnership and RNR Production in connection with the
Partnership's previous sale of 20% of the Royalty to RNR Production. In addition, and pursuant to the Option Agreement, Chevron, as the Managing General Partner of the Partnership, provided RNR
Production with formal notice that the Partnership would be marketing additional Royalty interests and that RNR Production must exercise its option to purchase the additional Royalty within ten days
of the receipt of such notice. RNR Production indicated that it was not interested in purchasing an additional part of the Royalty pursuant to the Option Agreement. Accordingly, the Trustees, by
letter dated October 16, 2012, provided written notice to Chevron to proceed with an alternative sale process to sell such portion, and only such portion, of the Royalty that will provide the
Trust with a current distribution equal to $1,000,000 from the proceeds of such sale. Based on a recommendation from Chevron, as the Managing General Partner of the Partnership, Chevron marketed for
sale by the Partnership the entire Royalty; however, the Trust reserved the right to sell only a portion of the Royalty. Also based on a recommendation from Chevron, Chevron engaged EnergyNet.com to
conduct the marketing process and related auction of the Royalty. EnergyNet.com handled the Partnership's sale of a portion of the Royalty to RNR Production in 2011. In December 2012 following the due
date for any bids for the purchase of the Royalty, the Trustees elected to delay any further action with respect to the proposed sale by the Partnership of the Royalty. Accordingly, the Trustees
instructed Chevron to delay any further action regarding a potential sale and the Trustees are continuing to evaluate the alternatives available to the Trust.

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. 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 and no distributions have been made to Unit holders since
January 9, 2009. In the fourth quarter of 2010, Chevron withdrew $4,304,894 from the Special Cost Escrow account of the Working Interest Owners (a reserve fund for certain costs) to cover
expenses incurred in connection with the plugging and abandonment of Eugene Island 339, which served to reduce the amount by which production costs exceeded the proceeds from production; however,
additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the terms of the Conveyance if, and when, Net Proceeds would otherwise be payable on the
Royalty. 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 any remaining expenditures required to plug and abandon the wells on Eugene Island 339.

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The
platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike. Chevron has completed the work required to clear the remaining infrastructure and abandon
existing wells, with estimated costs to the Royalty relating thereto of approximately $19.8 million, approximately $19.76 million of which had been incurred through January 31,
2013. In December 2009, Chevron entered into a participation agreement with Arena to assist in the redevelopment as a farmout of portions 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 was drilled in 2010 but drilling activity was suspended in July
2010. Chevron and Arena revised and amended the participation agreement (as amended, the "Arena Agreement") in response to Notice to Lessees No. 2010-N05, "Increased Safety Measures
for Energy Development on the OCS," and the revised redevelopment plan provided for setting a platform at Eugene Island 338 and drilling wells into Eugene Island 338 and Eugene Island 339 from the
platform. Pursuant to the terms of the Arena Agreement, Arena could earn an assignment of 65% of Chevron's working interests in Eugene Island 338 and Eugene Island 339 following completion of certain
drilling and development operations. Following completion of the first well on Eugene Island 339 by Arena and other drilling and development operations in the fourth quarter of 2012, Chevron assigned
65% of Chevron's working interests in Eugene Island 338 and Eugene Island 339 to Arena, effective as of December 15, 2009, the effective date of the Arena Agreement. In accordance with the
Arena Agreement, the working interest assigned to Arena is not burdened by the Royalty, and the Royalty held by the Partnership with respect to such properties has been reduced proportionately. As a
result of such assignment, the Royalty held by the Partnership on Eugene Island 339 has been reduced by 65%. 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. In November 2010, the platform at Ship Shoal 182/183 was shut-in for tank replacement and production has slowly returned thereafter. Production
was shut-in on multiple
occasions during 2012 for various facility improvement projects during which time production was temporarily impacted. 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. The lease
for West Cameron 643 expired in May 2010 and Chevron has been informed by Hilcorp that Hilcorp completed the plugging and abandoning of the wells at West Cameron 643 in October 2012. The lease for
East Cameron 371 expired on March 31, 2010 and plugging and abandonment work remains to be completed.

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

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Royalty
Properties. Chevron reached settlements that provide Chevron with insurance proceeds associated with damages that Chevron's assets sustained from Hurricane Ike. The allocated portion thereof
with respect to the Partnership's interest in Eugene Island 339, as a Royalty Property, was approximately $781,000. Chevron applied $400,000 thereof in the first quarter of 2011 and applied the
remaining amount of approximately $381,000 in the fourth quarter of 2012. All such allocated insurance proceeds were applied to the Partnership's portion of the aggregate cost to plug and abandon the
wells subject to the Royalty on Eugene Island 339. In September 2012, Chevron informed the Trust that the estimate of the aggregate cost to the Royalty to plug and abandon the wells subject to the
Royalty on Eugene Island 339 had increased from approximately $18.7 million to approximately $19.8 million. In March 2013, Chevron informed the Trust that of the estimated
$19.8 million of aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339, approximately $19.76 million had been incurred through January 31, 2013.
If Production Costs of the Royalty Properties exceed the Gross Proceeds 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 October 31, 2012, 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 $7.9 million, net to the entire Royalty. Such amount reflects adjustments in 2012, including an
insurance credit of approximately $381,000 received by Chevron and allocated for the benefit of the Royalty with respect to Eugene Island 339 in 2012. The excess development and production costs have
decreased from $7.9 million to $6.9 million (or $5.5 million, net to the Trust's
remaining 20% royalty interest) as of January 31, 2013, reflecting increased production from the Royalty Properties and the benefit of the audit adjustment for Eugene Island 339.

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, worldwide political conditions, 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 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
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

16

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administrative
expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the
Trust has not received sufficient Net Proceeds to maintain the reserve at such level. During the three months ended March 31, 2013, the Trust decreased its reserve by $176,360, to pay current
expenses, resulting in a reserve balance of $47,565 as of March 31, 2013, or approximately 6% of the average annual expenses of the Trust during the three-year period ended
March 31, 2013. As of December 31, 2012, the reserve was $223,925 or 27% of the average annual expenses during the three year period ended December 31, 2012.

As
discussed under "Operations," in January 2010, the Trust engaged an 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 and such review is currently ongoing. The Corporate Trustee had requested Chevron to pay any adjustments resulting
from such audit directly to the Partnership; however, Chevron instead credited any such adjustments against the Partnership's share of allocated expenses for the Royalty Properties. As a result, there
will be no current payments to the Partnership resulting from such audit.

The
accompanying condensed financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on the going concern basis
assume the realization of assets and the settlement of liabilities in the normal course of business. 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. Certain potential alternatives available to the Trustees are described in Note 6 to the condensed financial statements. The
condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty. See Notes 2 and 6 to the condensed financial statements.

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, 2012 future net revenues attributable to the Trust's royalty interests were estimated at $14.5 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, 2012 in order to correspond with distributions to
the Trust. Such reserve study also indicates that approximately 49% of the future net revenues from the Royalty Properties are expected to be received by the Trust by October 31, 2014. The
reserve study does include projected reserves attributable to the well drilled by Arena during the fourth quarter of 2012 on Eugene Island 339 but does not include 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. In September 2012,
Chevron informed the Trust that the estimate of the Royalty's net portion of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from
approximately $18.7 million to approximately $19.8 million. In March 2013, Chevron informed the Trust that of the estimated $19.8 million, approximately $19.76 million of
which had been incurred through January 31, 2013. 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

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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, 2012. 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 2013, there were no funds released or
escrowed from the Special Cost Escrow account. As of March 31, 2013, $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in
the condensed 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.

In
the fourth quarter of 2010, Chevron withdrew $4,304,894 from the Special Cost Escrow Account to cover expenses incurred in connection with the plugging and abandonment of Eugene
Island 339, leaving a balance of $1,000 in the Special Cost Escrow Account. After taking into account such withdrawal, aggregate development and production costs in excess of the related proceeds for
the royalty Properties as of January 31, 2013 was approximately $6.9 million, net to the entire Royalty (or $5.5 million, net to the Trust's remaining 20% royalty interest);
however, additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the Conveyance if, and when, Net Proceeds would otherwise be payable on the
royalty. During 2012, there were no funds

18

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released
from or escrowed into the Special Cost Escrow account. As of March 31, 2013, $1,000 remained in the Special Cost Escrow account.

In
connection with the sale of 20% of the Royalty by the Partnership in October 2011, the Partnership also assigned 20% of its rights and obligations with respect to the Special Cost
Escrow.

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.

Three Months Ended March 31, 2013 and 2012



Royalty income was $0 for the three months ended March 31, 2013 and 2012. Gross proceeds for the underlying Royalty Properties
exceeded development and protection costs for the months of November and December 2012 and January 2013 by $3,703,850, or $740,770 attributable to the Trust. However, the Net Proceeds were applied to
reduce the accumulated excess cost carry forward, which represents the amount by which the aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the
related proceeds of the protection, and as a result there was no royalty income for the quarter ended March 31, 2013. In comparison, there were no positive Net Proceeds attributable to the
Royalty Properties for the production period attributable to the first quarter of 2012.

General
and administrative expenses for the Trust were $176,365 for the three months ended March 31, 2013 compared to $165,686 for the three months ended March 31, 2012.
The increase is due to the timing of the recording of expenses.

The
reserve for future Trust expenses decreased $176,360 from December 31, 2012 to March 31, 2013 due to payments for Trust expenses.

There
was no distributable income for each of the three months ended March 31, 2013 and March 31, 2012 and therefore no distributions to unit holders.

For
the three months ended March 31, 2013, the Trust had undistributed net income of $740,770, representing the Trust's portion of the undistributed net income of $3,703,850
associated with the Royalty Properties for the three months ended March 31, 2013. The net income for the Royalty Properties reflects the benefit of an audit adjustment of Eugene Island 339,
which resulted in additional proceeds of $1,869,919 ($373,984 net to the Trust) for the three months ended March 31, 2013, as well as prior period adjustments for Eugene Island 342. The
cumulative undistributed net loss for the Trust was $5,552,557 as of March 31, 2013. 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.

19

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The following financial and operational information has been based on information provided to the Corporate Trustee by the Managing
General Partner. 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 $3,803,944 in the first quarter of 2012 to $2,821,975 in the first quarter of 2013, due to a decrease in net
crude oil production from 34,429 barrels in the first quarter of 2012 to 27,112 barrels in the first quarter of 2013. The decrease in volumes was due to multiple shut ins for facility
improvement projects during the first quarter 2013. There was also a decrease in the average crude oil price received from $110.49 per barrel in the first quarter of 2012 to $104.09 per barrel for the
same period in 2013. Gas revenues decreased from $153,138 in the first quarter of 2012 to $14,476 in the first quarter of 2013, due to a decrease in gas production from 44,867 Mcf in the first quarter
of 2012 to 3,479 Mcf in the first quarter of 2013 also as a result of the shut ins during the first quarter of 2013. The average gas revenue price received increased from $3.41 per Mcf in the first
quarter of 2012 to $4.16 per Mcf for the same period in 2013. Capital expenditures decreased from $305,543 in the first quarter of 2012 to $162,195 in the first quarter of 2013. Operating expenses
increased from $840,940 in the first quarter of 2012 to $901,198 for the same period in 2013.

Eugene
Island 339 net crude oil revenues were $0 in the first quarter of 2012 and $852,014 in the first quarter 2013. There was suspended drilling activity and, therefore, no production
in the first quarter of 2012. Net crude oil production was 19,958 barrels in the first quarter of 2013. The first quarter 2013
revenues and production include and reflect the benefit of an audit adjustment of Eugene Island 339. While limited production at one well on Eugene Island 339 commenced in December 2012, no actual
proceeds or revenues were received from Eugene Island 339 for the months of November and December 2012 and January 2013. Gas revenues were $0 in the first quarter 2012 and, including the results of
the audit adjustment, $1,884,307 in the first quarter 2013. There was no gas production and thus no revenues in the first quarter of 2012 also a result of the suspended drilling. As a result of the
audit adjustment, gas production was 162,885 Mcf in the first quarter 2013. Capital expenditures were $7,532 in the first quarter of 2012 and $0 in the first quarter of 2013. Operating expenses
decreased from $6,364,905 in the first quarter of 2012 to $277,231 in the first quarter of 2013 due primarily to decreased well and platform abandonment costs in the first quarter of 2013 as compared
to the first quarter of 2012.

South
Timbalier 36/37 crude oil revenues decreased from $144,124 in the first quarter of 2012 to $106,214 for the same period in 2013 due primarily to a decrease in oil production
volumes, and a decrease in average price received. There was a decrease in crude oil production volumes to 995 barrels in the first quarter of 2013 from 1,269 barrels in the first
quarter of 2012. The average crude oil price received decreased from $113.56 per barrel in the first quarter of 2012 to $106.72 per barrel in the first quarter of 2013. Gas revenues decreased from
$11,931 in the first quarter 2012 to $8,490 in the first quarter of 2013 due to a decrease in gas production and a decrease in the average natural gas price received. There was a decrease in natural
gas volumes from 3,149 Mcf in the first quarter of 2012 to 2,485 Mcf in the first quarter of 2013. The average natural gas price received decreased from $3.79 per Mcf in the first quarter of 2012 to
$3.42 per Mcf in the first quarter of 2013.

20

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Capital
expenditures decreased from $8,907 in the first quarter of 2012 to $3,814 in the first quarter of 2013. The costs in the first quarter 2013 were primarily associated with the facility
improvements. Operating expenses increased from $7,135 in the first quarter of 2012 to $14,486 in the first quarter of 2013 due to workover repairs conducted in during the first quarter 2013.

Production
from Eugene Island 342 ceased in the first quarter of 2011 because a third-party pipeline from the field was shut in due to a leak. Although production resumed in
July 2012, Chevron has been informed by Apache Corporation, the operator of Eugene Island 342, that production has again ceased due to leaks in the third-party pipeline. While there was no
actual production of oil or gas from Eugene Island in the first quarter of 2013, as a result of a prior period adjustment, net crude oil revenues for the first quarter of 2013 were $72,530 compared to
$0 in the prior year period. As a result of the adjustment, net crude oil production was 1,776 barrels in the first quarter of 2013 while there was no crude oil production in the first quarter
of 2012. Gas revenues were $0 in the first quarter of 2012 while gas revenues of $14,993 were recorded in the first quarter of 2013 as a result of the prior period
adjustment. There was no gas production in the first quarter of 2012 but as a result of the adjustment, gas production of 3,377 Mcf were recorded in the first quarter of 2013. There were no capital or
operating expenses recorded in the first quarter of 2012 and 2013.

Including
the results of the audit adjustment for Eugene Island 339 and prior period adjustment for Eugene Island 342, crude oil and condensate revenues decreased $95,335, or 2%, to
$3,852,733 in the first quarter of 2013 from $3,948,068 in the first quarter of 2012. Oil volumes during the first quarter of 2013 increased 39% to 49,840 barrels, compared to
35,698 barrels of oil produced in the first quarter of 2012. The increase in volumes is due primarily to the audit adjustment for Eugene Island 339 and, to a lesser extent, the adjustment for
Eugene Island 342. The average price received for crude oil and condensate production decreased 5.8%, or $6.42, to $104.18 per barrel in the first quarter of 2013 from $110.60 per barrel in the first
quarter of 2012, excluding the impact of the adjustments for Eugene Island 339 and Eugene Island 342.

Including
the results of the audit adjustment for Eugene Island 339 and the prior period adjustment for Eugene Island 342, gas revenues increased $1,757,196, or 1064%, to $1,922,265 in
the first quarter of 2013 from $165,069 in the first quarter of 2012. Gas volumes during the first quarter of 2013 increased 258% to 172,227 Mcf, compared to 48,016 Mcf produced in the first quarter
of 2012. The increase in volumes is due primarily to the audit adjustment for Eugene Island 339 and, to a lesser extent, the adjustment for Eugene Island 342. The average price received for natural
gas production was $3.85 per Mcf in the first quarter of 2013 compared to $3.44 per Mcf in the first quarter of 2012, excluding the impact from the adjustments for Eugene Island 339 and Eugene Island
342. As a result of the adjustments, gas products revenue decreased $531,905, or 2908%, to $(513,614) in the first quarter of 2013 from $18,291 in the first quarter of 2012. Gas products volumes
during the first quarter of 2013 decreased 2464% to (348,234) gallons, compared to 14,727 gallons in the first quarter of 2012, also as a result of the adjustments.

Capital
expenditures decreased by $140,908, or 84%, from $306,917 in the first quarter of 2012 to $166,009 in the first quarter of 2013. The higher amount of capital expenditures during
the first quarter of 2012 relate primarily to facility improvement projects and drilling and completion costs associated with a well at Ship Shoal 182/183.

Production
expenses decreased by $6,170,996, or 81%, from $7,562,520 in the first quarter of 2012 to $1,391,524 in the first quarter of 2013. The decrease in operating expenses is due
primarily to less

21

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well
and platform abandonment work being conducted at Eugene Island 339 in the first quarter of 2013 as compared to the first quarter of 2012.

The
Royalty Properties had undistributed net income of $3,703,850 in the first quarter of 2013 compared to net loss of 3,787,055 for the first quarter of 2012 due primarily to the audit
adjustments for Eugene Island 339 and Eugene Island 342.

In
the first quarter of 2013, there were no funds released from or escrowed into the Special Cost Escrow account. As of March 31, 2013, $1,000 remained in the Special Cost Escrow
account. The funds held in the Special Cost Escrow account are not reflected in the condensed 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.

Operations

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.

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.

In
September 2012, Chevron informed the Trust that the estimate of the aggregate cost to the Royalty to plug and abandon the wells subject to the Royalty on Eugene Island 339 had
increased from approximately $18.7 million to approximately $19.8 million. In March 2013, Chevron informed the Trust that the estimate of the aggregate cost to the Royalty to plug and
abandon the wells subject to the Royalty on Eugene Island 339 had not changed and approximately $19.76 million had been incurred through January 31, 2013.

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 Production, or "SOP," that, if approved by the regional supervisor of the BOEM allows additional time to
restore production in the event of certain circumstances, such as hurricanes and other events beyond the control of the operator. Although Chevron successfully obtained a series of SOPs and, with the
participation of Arena, obtained additional SOPs resulting in the restoration of limited production at Eugene Island 339, other Working Interest Owners have been unable to timely restore production or
obtain an SOP and as a result, many of the leases covering the Royalty Properties have been terminated or expired thereby reducing the proceeds payable to the Trust.

22

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On
December 15, 2009, Chevron entered into the Arena Agreement with Arena to assist in the redevelopment as a farmout of portions of Eugene Island 338 and 339. Pursuant to the
terms of the Arena Agreement, Arena could earn an assignment of 65% of Chevron's working interests in Eugene Island 338 and Eugene Island 339. Chevron holds a 50% interest in Eugene Island 339, which
interest is included in the 5500' and the 4500' sand units; 42.05% of all production from the 5500' sand unit is allocated to Eugene Island 339 and 38.50% of the gas production and 24.44% of the oil
production from the 4500' sand unit is allocated to Eugene Island 339. Pursuant to the terms of the Conveyance, Chevron may enter into a farmout agreement whereby Chevron assigns any portion of its
interest in the Royalty Properties free and clear of the Royalty, and the Royalty will be reduced in the same proportion as that in which the Royalty Property is reduced. Under the terms of the
Conveyance, a "farmout agreement" is defined as an agreement with a third party requiring or permitting the performance of drilling or development operations on a Royalty Property, and for which all
or substantially all of the consideration is the transfer of an interest in a Royalty Property. On August 4, 2012, Arena completed installation of the remaining topside decks of the structure
and on August 16, 2012, Arena commenced mobilization of the H&P 100 platform rig components. On September 28, 2012, Arena spud the OCS-G 2318 Well No. K002 and production
from this well was realized in the fourth quarter of 2012. Pursuant to the terms of the Arena Agreement, following completion of the well and the other drilling and development operations, Chevron
assigned 65% of
Chevron's working interests in Eugene Island 338 and Eugene Island 339 to Arena, effective as of December 15, 2009, the effective date of the Arena Agreement. In accordance with the Arena
Agreement, the working interest assigned to Arena is not burdened by the Royalty, and the Royalty held by the Partnership with respect to such properties has been reduced proportionately. As a result
of such assignment, the Royalty held by the Partnership on Eugene Island 339 has been reduced by 65%. Chevron has informed the Trust that Arena has also completed a second well pursuant to the Arena
Agreement and production has commenced from the second well. A third well is expected to be completed by Arena in the second quarter of 2013. Chevron has indicated that upon the drilling and
completion of this third farmout well, Arena will have no further obligations under the Arena Agreement with respect to the redevelopment of Eugene Island 338 and 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. 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 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 was
subsequently repaired and Ship Shoal 182/183 was reopened on May 1, 2010 after a 36-day shut-in. In November 2010, the platform at Ship Shoal 182/183 was
shut-in

23

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for
a scheduled tank replacement and production has slowly returned thereafter. Production was shut-in on multiple occasions during 2012 for various facility improvement projects during
which time production was temporarily impacted.

Production
from Eugene Island 342 ceased in the first quarter of 2011 because a third-party pipeline from the field was shut in due to a leak. While production resumed in
July 2012, Chevron has been
informed by the operator of Eugene Island 342 that production has again ceased due to leaks in the third-party pipeline.

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. As part of such process, Chevron agreed that $22,197 in adjustments were appropriate, which were credited in the first quarter of 2011. An additional $49,792 was credited in the fourth
quarter of 2012. Chevron did not pay these amounts to the Partnership or the Trust, but credited such amounts against the Partnership's share of allocated expenses for the Royalty Properties. Chevron
also agreed that $608,409 of expenses with respect to Eugene Island 339 in the first quarter of 2009 that were previously allocated to the Partnership should have been charged to Chevron. Credit for
$287,594 of such amount was made in the second quarter of 2011, with the remaining $320,815 credited in the third quarter of 2011. No assurance can be provided as to the ultimate outcome of such audit
review process.

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 Royalties paid to the Trust during the periods
indicated. The following includes the effect of the audit adjustment of Eugene Island 339 and the prior period adjustment for Eugene Island 342. Net Proceeds due to the

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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)2013

2012Crude oil and condensate (bbls)


49,840


35,698Natural gas and gas products (Mcfe)


114,188


50,120Crude oil and condensate average price, per bbl

$
77.30
(2)
$
110.60Natural gas average price, per Mcf (excluding gas products)

$
11.16
(3)
$
3.44Crude oil and condensate revenues

$
3,852,733

$
3,948,068Natural gas and gas products revenues


1,408,651


183,360Production expenses


(1,391,524
)

(7,562,520
)Capital expenditures


(166,009
)

(306,917
)Interest





(49,046
)Undistributed net loss (income)(4)


(3,703,850
)

3,787,055Refund of (provision for) Special Cost Escrow





Net Proceeds





Royalty interest


x20
%

x20
%Partnership share





Trust interest


x99.99
%

x99.99
%Trust share of Royalty Income(5)

$


$



(1)Amounts
are based on production for the three-month period ended January 31 of each year, respectively, and include the results of the adjustments
for Eugene Island 339 and Eugene Island 342.(2)Excluding
the adjustments, the average price was $104.18 per barrel.(3)Excluding
the adjustments, the average price was $3.85 per Mcf.(4)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.(5)See
"Trustee's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources" and Note 4 to
the Notes to the Condensed Financial Statements under Item 1 of Part I of this Form 10-Q for a discussion regarding uncertainty of distributions.


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Critical Accounting Policies

Basis of Accounting.The Trust's condensed financial statements are prepared on a modified cash basis, which is a comprehensive basis
of accounting
other than GAAP. This method of accounting is consistent with reporting of taxable income to the Trust unitholders. The most significant differences between the Trust's condensed financial statements
and those prepared in accordance with GAAP are:



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 condensed financial statements of the Trust differ from condensed financial statements prepared in accordance with GAAP, 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. This comprehensive basis of accounting other than GAAP
corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E,Financial
Statements of Royalty Trusts.

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 any of the
Working Interest Owners.

Amortization of Overriding Royalty Interest.The Trust amortizes the investment in overriding royalty interest using the
units-of-production method. The Trust's rate of recording amortization is dependent upon the estimates of total proved reserves, which incorporates various assumptions and
future projections. If the estimates of total proved reserves decline
significantly, the rate at which the Trust records amortization expense would increase, reducing Trust corpus. Such a decline in reserves may result from lower commodity prices, which may make it
uneconomic to produce from higher cost

26

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fields.
The Trust is unable to predict changes in reserve quantity estimates as such quantities are dependent on future economic and operational conditions.

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

New Accounting Pronouncements

There were no accounting pronouncements issued during the three months ended March 31, 2013 applicable to the Trust or its
condensed financial statements.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the
Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

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 Condensed
Financial Statements included in Item 1 of this Form 10-Q.

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

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,

27

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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. Michael J. 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 2012 Form 10-K 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, 2013,
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 the risk factors previously disclosed in the Trust's response to Item 1A. to
Part 1 of its Form 10-K for the year ended December 31, 2012.

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)


29

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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


30

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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/ MICHAEL J. ULRICH Michael J. Ulrich Vice President


Date:
May 15, 2013

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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