UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549



FORM 10-Q

ý

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended September 30, 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 November 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"), Item 1A of Part II of the Trust's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2013 and this Form 10-Q 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 (DEFICIT)

September 30,
2013

December 31,
2012AssetsCash and cash equivalents

$
137,241

$
223,925Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,252,797 and $28,250,347, respectively


15,247


17,308Total assets

$
152,488

$
241,233Liabilities and Trust Corpus (Deficit)Note payable

$
300,000

$
Distribution payable to Unit holders





Reserve for future Trust expenses





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


(147,512
)

17,308Total liabilities and Trust corpus (deficit)

$
152,488

$
241,233


CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME

Three Months Ended
September 30,

Nine Months Ended
September 30,2013

2012

2013

2012Royalty income

$


$


$


$
Interest income


4


11


11


524


11


11


52Decrease in reserve for future Trust expenses





128,400


223,925


617,284Proceeds from note used for Trust expenses


118,589





162,759


General and administrative expenses


(118,593
)

(128,411
)

(386,695
)

(617,336
)Distributable income

$


$


$


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

$
.000000

$
.000000

$
.000000

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

$
.000000

$
.000000

$
.000000

$
.000000


CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (DEFICIT)

Three Months
Ended September 30,

Nine Months
Ended September 30,2013

2012

2013

2012Trust corpus, beginning of period

$
(28,441
)
$
18,433

$
17,308

$
19,508Distributable income











Distribution payable to Unit holders











Proceeds from note used for Trust expenses


(118,589
)




(162,759
)

Amortization of net overriding royalty interest


(482
)

(564
)

(2,061
)

(1,639
)Trust corpus (deficit), end of period

$
(147,512
)
$
17,869

$
(147,512
)
$
17,869




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 equivalent to a 25% net profits interest (the
"Original Royalty") 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. The term "Original Royalty" shall refer to the initial 25% net profits interest in the
Royalty Properties and the term "Royalty" shall refer to the applicable net profits interest held from time to time by the Partnership following the sales described in Note 3.

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)



In
October 2011, the Partnership consummated a sale of 20% of its overriding royalty interest (or 5% of 8/8ths) and retained an 80% interest in the Original Royalty (or 20%
of 8/8ths). See Note 3.

On
October 31, 2013, the Partnership consummated the sale of 25% of its remaining interest in the Original Royalty (or 5% of 8/8ths) and following such sale now holds 60% of the
Original Royalty interest (or 15% of 8/8ths). 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 (collectively, the "Trustees").

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.

(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 the Partnership's interest in the Original Royalty. The
Original Royalty initially represented a 25% net profits interest but after the previous sales by the Partnership, the Royalty now represents a 15% net profits interest.

3

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

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

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 (deficit), earnings and distributions, as follows:



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 (deficit) 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.

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

4

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

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

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 consummated a sale of 20% of its interest in the Original Royalty (or 5% of 8/8ths) to a third party; as a result, on the last business day of each calendar quarter after August 1,
2011 and prior to August 1, 2013, the Working Interest Owners were to pay to the Partnership 20% of the Net Proceeds for the immediately preceding Quarterly Period. As discussed in
Note 3Net Overriding Royalty Interest, on October 31, 2013, but effective as of August 1, 2013, the Partnership consummated the sale of 25% of its interest in the
Original Royalty (or 5% of 8/8ths) to a third party and as a result, on the last business day of each calendar quarter after August 1, 2013, the Working Interest Owners are to pay to the
Partnership 15% 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 Partnership during the quarter ended
September 30, 2013 would substantially represent the revenues and expenses from the Royalty Properties from May 2013 through July 2013. Similarly, any cash conveyed to the Trust from the
Partnership during the quarter ended September 30, 2012 would substantially represent the revenues and expenses from the Royalty Properties from May 2012 through July 2012. However, there was
no cash conveyed to the Trust from the Partnership pursuant to its overriding royalty interest in the Royalty Properties from either May 2013 through July 2013 or May 2012 through July 2012. The
financial and operating information included in this Form 10-Q for the three months ended September 30, 2013 and September 30, 2012 represents financial and operating information
with respect to the Royalty Properties for the immediately preceding months of May, June and July. Similarly, financial and operating information with respect to the Royalty Properties for the nine
months ended September 30, 2013 and September 30, 2012 represents financial and operating information with respect to the Royalty Properties for the immediately preceding months of
November through July. Income received pursuant to the Partnership's overriding royalty interest 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 (deficit). 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

5

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

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

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 or nine months ended September 30, 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 interests in the Original Royalty 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 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 September 30, 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 a distribution associated
with net proceeds from the Royalty 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.

6

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(3) Net Overriding Royalty Interest

On October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2011 Royalty Sale") of 20% of the Original Royalty (or 5% of
8/8ths). The 2011 Royalty Sale generated $1,600,000 in gross proceeds and occurred as part of a formal auction process for the Partnership's overriding royalty interest in the Royalty Properties. 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 used such net proceeds solely for the
payment of expenses of the Trust.

The
2011 Royalty 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
2011 Royalty Sale was made to RNR Production on October 27, 2011, though the assignment was effective as of August 1, 2011.

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 12, 2013, the
Trustees provided written notice to Chevron USA, Inc. ("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 remaining interest in the Original Royalty
so that the Trust will have sufficient funds to pay its liabilities. 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 2011 Royalty Sale.

On
October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2013 Royalty Sale") of 25% of its remaining interest in the
Original Royalty (or 5% of 8/8ths) and following such sale the Partnership now holds 60% of the overriding royalty interest (or 15% of 8/8ths). The 2013 Royalty Sale generated $1,200,000
in gross proceeds and occurred as part of a formal auction process for the Partnership's remaining overriding royalty interest in the Royalty Properties. The Trust received from the Partnership a
distribution of approximately $1,151,885, representing 99.99% of the net proceeds from the sale of $1,152,000. The Trust intends to use approximately $300,000 of such net proceeds to repay the Trust's
indebtedness under that certain Demand Promissory Note, dated May 23, 2013, in the original principal amount of $300,000, executed by the Trust and payable to The Bank of New York Mellon, N.A.,
(the "Note") and the remaining net proceeds for the payment of expenses of the Trust. The Partnership has retained a 60% interest in the Original Royalty, and thus the Partnership will receive in the
future only 15% of the Net Proceeds when there are sufficient Net Proceeds for distribution on the Partnership's Royalty.

The
2013 Royalty Sale is governed by a letter agreement, pursuant to which the Partnership and RNR Production made various representations and warranties, with related indemnification
obligations. In connection therewith, the Partnership and RNR Production executed a Partial Assignment of

7

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(3) Net Overriding Royalty Interest (Continued)

Overriding
Royalty Interests. The 2013 Royalty Sale to RNR Production closed on October 31, 2013, though the assignment was effective as of August 1, 2013.

Following
the 2013 Royalty Sale to RNR Production, the Partnership's remaining interest in the Original Royalty currently entitles the Trust to its share (99.99%) of 60% 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.

The
Trust's share of Royalty income was reduced by approximately $36,213 and $59,072, respectively, for each of the three months ended September 30, 2013 and September 30,
2012, and approximately $108,108 and $168,415, respectively, for each of the nine months ended September 30, 2013 and September 30, 2012, 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.

(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

8

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(4) Distributions to Unit Holders (Continued)

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 its interests
in the Royalty Properties, 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 Original
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. As of July 31, 2013, approximately $19.76 million of the estimated aggregate cost had been incurred. While the work may be complete, additional vendor invoices for this
work may be received in the future, which expenses will or could bear upon the proceeds which may be received from Eugene Island 339. 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 exceeded the related proceeds of production from the Royalty Properties by approximately $7.9 million, net to the entire Original Royalty. This
amount reflects adjustments in 2012, including an insurance credit of approximately $381,000 received by Chevron and allocated for the benefit of the overriding royalty interest with respect to Eugene
Island 339 in 2012. As of July 31, 2013, the excess development and production costs have decreased from $7.9 million to $5.6 million (or $4.5 million, net to the
Partnership's then-existing 20% Royalty), reflecting increased production from the Royalty Properties and the benefit of a working interest audit adjustment of Eugene Island 339 during the first
quarter of 2013.

For
the three months ended September 30, 2013, the Trust had undistributed net income of $706,727 representing the Trust's portion of the aggregate undistributed net income of
$3,533,636 associate with the Royalty Properties. For the nine months ended September 30, 2013, the Trust had undistributed net income of $1,846,250 representing the Trust's portion of the
aggregate undistributed

9

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(4) Distributions to Unit Holders (Continued)

net
income of $9,231,249 associated with the Royalty Properties. Included within the aggregate undistributed net income associated with the Royalty Properties for the first nine months of 2013 is a
working interest audit adjustment associated with the Royalty Properties for 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 $4,443,633, representing the Trust's portion of the aggregate undistributed net loss associated with the Royalty Properties through the production
period ended July 31, 2013. Undistributed net loss represents the amount of development and production costs associated with the Partnership's overriding royalty interest 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.

In
May 2013, the Bank of New York Mellon, N.A., an affiliate of the Corporate Trustee, made a loan of $300,000 to the Trust to enable the Corporate Trustee to pay administrative
expenses. See Note 9 for additional information regarding the loan and the restrictions on distributions as a result of such loan.

(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 September 30, 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 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.

10

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(5) Special Cost Escrow Account (Continued)

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

RNR
Production was the purchaser of the partial interests in the overriding royalty interest sold pursuant to the 2011 Royalty Sale and the 2013 Royalty Sale and now holds 40% of the
Original Royalty (or 10% of 8/8ths) and 40% of the Partnership's rights and obligations with respect to the Special Cost Escrow, which were assigned in connection with the 2011 Royalty Sale and the
2013 Royalty Sale.

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. As of December 31, 2012, the reserve
amount was $223,925 or 27% of the average annual expenses during the three year period ended December 31, 2012. Due to continuing expenses of the Trust, the reserve balance as of
September 30, 2013 was $0. All Trust expenses during the three months ended September 30, 2013 have been paid for through the partial use of loan proceeds. The use of loan proceeds has
reduced the Trust Corpus to a deficit of $147,512 as of September 30, 2013. However, in connection with the 2013 Royalty Sale, the Trust received a distribution of approximately $1,151,885,
representing 99.99% of the net proceeds from the sale of $1,152,000. The Trust will use such net proceeds to repay the Trust's indebtedness of approximately $300,000 to the Bank of New York Mellon,
N.A. pursuant to the Note and the remaining proceeds for the payment of expenses of the Trust.

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 Properties, and there is no guarantee that any further distributions will be made.

Pursuant
to the terms of the Trust Agreement, the Trustees are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that
cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no distributions will be made to the Unit holders
until the indebtedness created

11

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(6) Reserve For Future Trust Expenses (Continued)

by
such borrowings has been paid in full. As discussed in Note 9, the Trustees borrowed funds from which a portion of the proceeds were used to pay for Trust expenses.

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
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the 2011 Royalty Sale. The 2011 Royalty Sale generated $1,600,000 in gross
proceeds and occurred as part of a formal auction process for the Partnership's overriding royalty interest in the
Royalty Properties. 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 used such net
proceeds solely for the payment of expenses of the Trust. The 2011 Royalty Sale is governed by a letter agreement, pursuant to which the Partnership and 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 2011 Royalty
Sale was made to RNR Production on October 27, 2011 and the assignment was effective as of August 1, 2011.

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. As of September 30, 2013, the amount of such fees was approximately $245,000 in the aggregate. Such suspended fees will be recorded as an expense of the Trust when
invoiced by the Trustees and paid.

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 12, 2013, 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 remaining interest in the Original Royalty so that the Trust will have sufficient funds to pay its liabilities. Based on a
recommendation from Chevron, Chevron engaged EnergyNet.com, who handled the 2011 Royalty Sale, to conduct the marketing process and related auction of the Royalty.

On
October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the 2013 Royalty Sale of 25% of its remaining interest in the Original
Royalty (or 5% of 8/8ths) and following such sale the Partnership now holds 60% of the Original Royalty (or 15% of 8/8ths). The 2013 Royalty Sale generated $1,200,000 in gross proceeds
and occurred as part of a formal auction process for the Partnership's remaining overriding royalty interest in the Royalty Properties. The Trust received from the Partnership a distribution of
approximately $1,151,885, representing 99.99% of the net proceeds from the sale of $1,152,000. The Trust intends to use

12

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(6) Reserve For Future Trust Expenses (Continued)

approximately
$300,000 of such net proceeds to repay the Note outstanding as of September 30, 2013, and the remaining net proceeds for the payment of expenses of the Trust. The Partnership has
retained a 60% interest in the Original Royalty, and thus the Partnership will receive in the future only 15% of
the Net Proceeds when there are sufficient Net Proceeds for distribution on the Partnership's overriding royalty interest.

The
2013 Royalty Sale is governed by a letter agreement, pursuant to which the Partnership and 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 2013 Royalty Sale to RNR Production closed on
October 31, 2013 and the assignment was effective as of August 1, 2013.

(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) Note Payable

On May 23, 2013, the Trust executed the Note for $300,000 payable to The Bank of New York Mellon, N.A., an affiliate of the Corporate Trustee, serving as lender. The Note
evidences an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. The Note is due and
payable in cash on the earliest to occur of (i) the date written demand for payment is made by The Bank of New York Mellon, N.A. or (ii) May 23, 2014. The Note accrues interest at
a rate per annum equal to one-half percent (0.5%). Proceeds from the Note have been, and will continue to be, used solely for the payment of expenses of the Trust and no distributions will be made to
the Unit holders until the Note has been repaid in full. During the three months and nine months ended September 30, 2013, $118,589 and $162,759, respectively, of the proceeds from the Note
were used to pay for Trust expenses.

(10) Subsequent Events

On September 23, 2013, the Trust issued a press release announcing that there would be no trust distribution for the third quarter of 2013 for Trust unitholders of record on
September 30, 2013.

13

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(10) Subsequent Events (Continued)

On
October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the 2013 Royalty Sale. See Note 3 for additional information regarding
the 2013 Royalty Sale.

14

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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 form its share of the Net Proceeds from the Royalty Properties. Total
future net revenues attributable to the Partnership's interest in the Royalty held by the Partnership on October 31, 2012 were estimated at $14.5 million as of such date. 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. Accordingly, on May 23, 2013, the Trust executed a promissory note (the "Note") for
$300,000 payable to Bank of New York Mellon, N.A., an affiliate of the Corporate Trustee, which evidences an extension of credit for borrowed money authorized under Section 6.08 of the Trust
Agreement. The Note is due and payable in cash on the earliest to occur of (i) the date written demand for payment is made by The Bank of New York Mellon, N.A. or (ii) May 23,
2014. The Note accrues interest at a rate per annum equal to one-half percent (0.5%). Proceeds from the Note have been, and will continue to be, used solely for the payment of expenses of the Trust.
Pursuant to the Trust Agreement, no distributions will be made to the Unitholders until the Note has been repaid in full. During the three months and nine months ended September 30, 2013,
$118,589 and $162,759, respectively, of the proceeds from the Note were used to pay Trust expenses.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2011 Royalty Sale") of 20% of the Original Royalty (or 5% of
8/8ths). The 2011 Royalty Sale generated $1,600,000 in gross proceeds and occurred as part of a formal auction process for the Partnership's overriding royalty interest in the Royalty Properties. 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 used such net proceeds solely for the
payment of expenses of the Trust.

The
2011 Royalty 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

15

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and
warranties, with related indemnification obligations. In connection therewith, the Partnership and RNR Production executed a Partial Assignment of Overriding Royalty Interests. The 2011 Royalty
Sale was made to RNR Production on October 27, 2011, though the assignment was effective as of August 1, 2011.

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. As of September 30, 2013, the amount of such fees was approximately $245,000 in the aggregate. Such suspended fees will be recorded as an expense of the Trust when
invoiced by the Trustees and paid.

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 12, 2013, 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 remaining interest in the Original Royalty so that the Trust will have sufficient funds to pay its liabilities. Based on a
recommendation from Chevron, Chevron engaged EnergyNet.com, who handled the 2011 Royalty Sale, to conduct the marketing process and related auction of the Royalty.

On
September 23, 2013, the Trust issued a press release announcing that there would be no trust distribution for the third quarter of 2013 for Trust unitholders of record on
September 30, 2013.

On
October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2013 Royalty Sale") of 25% of its remaining interest in the
Original Royalty (or 5% of 8/8ths) and following such sale the Partnership now holds 60% of the overriding royalty interest (or 15% of 8/8ths). The 2013 Royalty Sale generated $1,200,000 in gross
proceeds and occurred as part of a formal auction process for the Partnership's remaining overriding royalty interest in the Royalty Properties. The Trust received from the Partnership a distribution
of approximately $1,151,885, representing 99.99% of the net proceeds from the sale of $1,152,000. The Trust intends to use approximately $300,000 of such net proceeds to repay the Trust's indebtedness
under that certain Demand Promissory Note, dated May 23, 2013, in the original principal amount of $300,000, executed by the Trust and payable to The Bank of New York Mellon, N.A., (the "Note")
and the remaining net proceeds for the payment of expenses of the Trust. The Partnership has retained a 60% interest in the Original Royalty, and thus the Partnership will receive in the future only
15% of the Net Proceeds when there are sufficient Net Proceeds for distribution on the Partnership's Royalty.

The
2013 Royalty Sale is governed by a letter agreement, pursuant to which the Partnership and 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 2013 Royalty Sale to RNR Production closed on
October 31, 2013, though the assignment was effective as of August 1, 2013.

Following
the 2013 Royalty Sale to RNR Production, the Partnership's remaining interest in the Original Royalty currently entitles the Trust to its share (99.99%) of 60% 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

16

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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.

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
Partnership's 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.

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 applicable to the Original Royalty of approximately $19.8 million, approximately
$19.76 million of which had been incurred through July 31, 2013. While the work may be complete, additional vendor invoices for this work may be received in the future, which expenses
will or could bear upon the proceeds which may be received from Eugene Island 339. 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

17

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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 and 2013 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 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 Original Royalty at such time 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. As of July 31, 2013, approximately
$19.76 million of the estimated aggregate cost had been incurred. 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

18

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entire
Original 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 overriding royalty
interest with respect to Eugene Island 339 in 2012. The excess development and production costs have decreased from $7.9 million to $6.4 million (or $4.5 million, net to the
Partnership's then-existing 20% Royalty) as of July 31, 2013, reflecting increased production from the Royalty Properties and the benefit of the working interest audit adjustment for Eugene
Island 339 during the first quarter of 2013.

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 distributions
received by the Trust from the Partnership 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
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 September 30, 2013, the Trust utilized $118,589 proceeds from the Note to pay
for Trust expenses and the reserve balance was $0 as of September 30, 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

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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 Partnership's overriding royalty interest as of such date were estimated at $14.5 million.
Estimates of proved oil and gas reserves attributable to the Partnership's overriding royalty interest are based on existing economic and operating conditions in effect at October 31, 2012 in
order to correspond with cash 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 Original 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. As of July 31, 2013, approximately $19.76 million of this amount had been
incurred. While the work may be complete, additional vendor invoices for this work may be received in the future, which expenses will or could bear upon the proceeds which may be received from Eugene
Island 339. Because the Trust will terminate in the event estimated future net revenues attributable to the Royalty fall below $1.2 million (assuming no further sales of any interests in the
Royalty), it would be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination of the Trust, the Trustees
will sell for cash all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied. The estimates of
future net revenues discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties present in estimating future net revenues
for the Royalty Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed by DeGolyer and
MacNaughton. In addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth above is
qualified in its entirety by reference to the 2012 10-K. The
2012 10-K is available at the website of the Securities and Exchange Commission ("SEC") atwww.sec.govor upon request from the Corporate Trustee.

Special Cost Escrow Account

The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling
platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in
the Conveyance, the amount of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net
revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of

20

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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 nine months of 2013, there were no funds
released or escrowed from the Special Cost Escrow account. As of September 30, 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 July 31, 2013 was approximately $5.6 million, net to the entire Original Royalty (or $4.4 million, net to the Trust's then-remaining 20% Royalty);
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 released from or escrowed into the Special Cost Escrow account. As of September 30, 2013, $1,000 remained in the Special Cost Escrow account.

RNR
Production was the purchaser of the partial interests in the overriding royalty interest sold pursuant to the 2011 Royalty Sale and the 2013 Royalty Sale and now holds 40% of the
Original Royalty (or 10% of 8/8ths) and 40% of the Partnership's rights and obligations with respect to the Special Cost Escrow, which were assigned in connection with the 2011 Royalty Sale and the
2013 Royalty Sale.

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 September 30, 2013 and 2012



Royalty income was $0 for the three months ended September 30, 2013 and 2012. Gross proceeds for the underlying Royalty
Properties exceeded development and protection costs for the months of

21

---



May,
June and July 2013 by $3,533,636 or $883,409 attributable to the entire Original Royalty, and $706,727 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 September 30, 2013. In comparison, there were no positive Net Proceeds attributable to the Royalty Properties for
the production period attributable to the third quarter of 2012.

General
and administrative expenses for the Trust were $118,593 for the three months ended September 30, 2013 compared to $128,411 for the three months ended September 30,
2012. The decrease is due to cost reduction measures taken by the Trustees to minimize expenses of the Trust and due to the timing of the recording of expenses.

The
Trust used $118,589 of proceeds from the Note to pay for the Trust expenses during the three months ended September 30, 2013.

There
was no distributable income for each of the three months ended September 30, 2013 and September 30, 2012 and therefore no distributions to unit holders.

For
the three months ended September 30, 2013, the Trust had undistributed net income of $706,727, representing the Trust's portion of the aggregate undistributed net income of
$3,533,636 associated with the Royalty Properties. Included within such amount are revenues received by Chevron from the operator of Eugene Island 342 for the period of July 2010 through January 2013.
The cumulative undistributed net loss for the Trust and attributable to its then-remaining 20% Royalty was $4,443, 633 as of July 31, 2013. Undistributed net loss represents the amount of
development and production costs associated with the overriding royalty interest 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.



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 increased from $2,963,103 in the third quarter of 2012 to $3,219,357 in the third quarter of 2013, due to an increase in net crude oil production
from 28,049 barrels in the third quarter of 2012 to 31,038 barrels in the third quarter of 2013. The increase in volumes was due to multiple shut ins for facility improvement projects during the third
quarter 2012. The increase in volumes was partially offset by a decrease in the average crude oil price received from $105.64 per barrel in the third quarter of 2012 to $103.72 per barrel for the same
period in 2013. Gas revenues decreased from $78,110 in the third quarter of 2012 to $66,003 in the third quarter of 2013, due to a decrease in gas production from 35,453 Mcf in the third quarter of
2012 to 14,702 Mcf in the third quarter of 2013 as a result of the shut ins during the third quarter of 2013. This decrease was

22

---



partially
offset by an increase in the average gas revenue price received from $2.20 per Mcf in the third quarter of 2012 to $4.49 per Mcf for the same period in 2013. Capital expenditures decreased
from $2,733,543 in the third quarter of 2012 to $44,863 in the third quarter of 2013. Operating expenses decreased from $1,170,790 in the third quarter of 2012 to $1,137,054 for the same period in
2013.

Eugene
Island 339 net crude oil revenues were $0 in the third quarter of 2012 and $1,144,375 in the third quarter 2013. There was suspended drilling activity and, therefore, no
production in the third quarter of 2012. Net crude oil production was 11,145 barrels in the third quarter of 2013. The third quarter of 2013 benefitted from production from three new wells at Eugene
Island 339. Gas revenues were $0 in the third quarter 2012 and $41,975 in the third quarter 2013. There was no gas production and thus no revenues in the third quarter of 2012 also a result of the
suspended drilling. Gas production was 9,913 Mcf in the third quarter 2013. Prior period adjustments to capital expenditures
resulted in a benefit of $42,673 in the third quarter of 2012. Capital expenditures were $0 in the third quarter of 2013. Operating expenses decreased from $2,790,790 in the third quarter of 2012 to a
benefit of $47,707 in the third quarter of 2013 due to decreased well and platform abandonment costs and the effect of prior period audit adjustments as compared to the third quarter of 2012.

South
Timbalier 36/37 crude oil revenues decreased from $119,784 in the third quarter of 2012 to $105,594 for the same period in 2013 due primarily to a decrease in the average price
received. The average crude oil price received decreased from $109.54 per barrel in the third quarter of 2012 to $86.18 per barrel in the third quarter of 2013. There was an increase in crude oil
production volumes to 1,225 barrels in the third quarter of 2013 from 1,093 barrels in the third quarter of 2012. Gas revenues increased from $7,046 in the third quarter 2012 to $12,614 in the third
quarter of 2013 due an increase in the average natural gas price received from $2.37 per Mcf in the third quarter of 2012 to $4.25 per Mcf in the third quarter of 2013. There was a slight decrease in
natural gas volumes from 2,977 Mcf in the third quarter of 2012 to 2,969 Mcf in the third quarter of 2013. Capital expenditures increased from $4,104 in the third quarter of 2012 to $16,270 in the
third quarter of 2013. The increased costs in the third quarter 2013 were primarily associated with the facility improvements. Operating expenses decreased from $10,489 in the third quarter of 2012 to
$9,891 in the third quarter of 2013 due to fewer workover repairs conducted during the third quarter of 2013.

Production
from Eugene Island 342 effectively ceased in the first quarter of 2011 because a third party pipeline from the field was shut in due to a leak. Following repairs to fix the
leak, limited production resumed in July 2012. Net crude oil revenues were $250,747 and net crude oil production was 2,546 barrels in the third quarter 2013. Of these amounts, $209,015 and 2,165
barrels relates to production prior to the third quarter of 2013. There were no meaningful revenues or production of oil or gas from Eugene Island 342 in the third quarter of 2012. As the underlying
interest in Eugene Island 342 is an overriding royalty interest, there were no capital or operating expenses recorded in the third quarter of 2012 and 2013.

Crude
oil and condensate revenues increased $1,637,186, or 53%, to $4,720,073 in the third quarter of 2013 from $3,082,887 in the third quarter of 2012. Oil volumes during the third
quarter of 2013 increased 58% to 45,954 barrels, compared to 29,143 barrels of oil produced in the third quarter of 2012. The increase in volumes is due primarily to the commencement of production of
three wells at Eugene Island 339 and increased production at Ship Shoal 182/183 during the third quarter of 2013. The average price received for crude oil and condensate production decreased 2.2%, or
$2.30, to $103.49 per barrel in the third quarter of 2013 from $105.79 per barrel in the third quarter of 2012.

23

---



Gas
revenues increased $35,437, or 42%, to $120,592 in the third quarter of 2013 from $85,155 in the third quarter of 2012. The average price received for natural gas production was
$4.38 per Mcf in the third quarter of 2013 compared to $2.22 per Mcf in the third quarter of 2012. Gas volumes during the third quarter of 2013 decreased 28% to 27,585 Mcf, compared to 38,430 Mcf
produced in the third quarter of 2012. The decrease in volumes is due primarily to decreased production at Ship Shoal 182/183 as a result of shut ins during the third quarter of 2013, despite
the commencement of production of three wells at Eugene Island 339. Gas products revenue increased $24,222, or 238%, to $34,405 in the third quarter of 2013 from $10,183 in the third quarter of 2012.
Gas products volumes during the third quarter of 2013 increased 241% to 47,963 gallons, compared to 14,068 gallons in the third quarter of 2012.

Capital
expenditures decreased by $2,633,840, or 98%, from $2,694,974 in the third quarter of 2012 to $61,134 in the third quarter of 2013. The higher amount of capital expenditures
during the third 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 $2,987,126, or 70%, from $4,267,426 in the third quarter of 2012 to $1,280,300 in the third quarter of 2013. The decrease in operating expenses is due
primarily to less well and platform abandonment work being conducted at Eugene Island 339 in the third quarter of 2013 as compared to the third quarter of 2012.

The
Royalty Properties had undistributed net income of $3,533,636 in the third quarter of 2013 compared to net loss of $3,814,240 for the third quarter of 2012 due primarily to the
increase in revenue and decrease in abandonment expenses at Eugene Island 339 and decrease in capital expenses at Ship Shoal 182/183.

In
the third quarter of 2013, there were no funds released from or escrowed into the Special Cost Escrow account. As of September 30, 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.

Nine Months Ended September 30, 2013 and 2012



Royalty income was $0 for the nine months ended September 30, 2013 and 2012. Gross proceeds for the underlying Royalty
Properties exceeded development and protection costs for the months November 2012 through July 2013 by $9,231,249, or $1,846,250 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 nine months ended September 30, 2013. In comparison, there were no positive Net Proceeds attributable to
the Royalty Properties for the production period attributable to the first nine months of 2012.

General
and administrative expenses for the Trust were $386,695 for the nine months ended September 30, 2013 compared to $617,336 for the nine months ended September 30,
2012. The

24

---



decrease
is due to cost reduction measures taken by the Trustees to minimize expenses of the Trust and due to the timing of the recording of expenses.

The
reserve for future Trust expenses decreased $223,925 from December 31, 2012 to September 30, 2013 due to payments for a portion of Trust expenses. The Trust used
$162,759 of proceeds from the Note to pay for the remaining Trust expenses during the nine months ended September 30, 2013.

There
was no distributable income for each of the nine months ended September 30, 2013 and September 30, 2012 and therefore no distributions to unit holders.

For
the nine months ended September 30, 2013, the Trust had undistributed net income of $1,846,250, representing the Trust's portion of the undistributed net income of $9,231,249
associated with the Royalty Properties for the nine months ended September 30, 2013. Included within the aggregate undistributed net income associated with the Royalty Properties is a working
interest audit adjustment associated with the Royalty Properties for Eugene Island 339 which resulted in additional proceeds of $1,869,919 ($373,984 net to the Trust) and revenues from Eugene Island
342 for the period July 2010 through January 2013. The cumulative undistributed net loss for the Trust was $4,443,633 as of July 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.



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 $8,646,163 in the first nine months of 2012 to $8,556,922 in the first nine months of 2013, due to a decrease in the average crude
oil price received from $109.37 per barrel in the first nine months of 2012 to $105.72 per barrel for the same period in 2013. This price decrease was partially offset by a slight increase in net
crude oil production from 79,056 barrels in the first nine months of 2012 to 80,938 barrels in the first nine months of 2013. Gas revenues decreased from $272,513 in the first nine months of 2012 to
$123,604 in the first nine months of 2013, due to a decrease in gas production from 97,457 Mcf in the first nine months of 2012 to 29,380 Mcf in the first nine months of 2013 as a result of the
shut-ins during the first quarter of 2013. The average gas revenue price received increased from $2.80 per Mcf in the first nine months of 2012 to $4.21 per Mcf for the same period in 2013. Capital
expenditures decreased from $4,377,145 in the first nine months of 2012 to $280,465 in the first nine months of 2013. Operating expenses increased from $3,487,628 in the first nine months of 2012 to
$3,526,878 for the same period in 2013.

Eugene
Island 339 net crude oil revenues were $0 in the first nine months of 2012 and $3,026,053, including a working interest audit adjustment of $852,014, in the first nine months of
2013. There was

25

---



suspended
drilling activity and, therefore, no production in the first nine months of 2012. Net crude oil production was 40,530 barrels in the first nine months of 2013, including a working interest
audit adjustment of 19,958 barrels. The first nine months 2013 revenues and production include and reflect the benefit of a working interest audit adjustment of Eugene Island 339. Production at one
well on Eugene Island 339 commenced in December 2012, a second well in March 2013 and a third well in May 2013, and each are included in the results for the first nine months of 2013. Gas revenues
were $0 in the first nine months of 2012 and, $1,945,959 in the first nine months of 2013, including the results of the working interest audit adjustment of $1,884,307. There was no gas production and
thus no revenues in the first nine months of 2012 also a result of the suspended drilling. Gas production was 178,889 Mcf in the first nine months of 2013, including the effect of the working interest
audit adjustments of 162,885 Mcf. Prior period audit adjustments to capital expenditures resulted in a benefit of $50,206 in the first nine months of 2012 and a benefit of $41,507 in the first nine
months of 2013. Operating expenses decreased from $10,833,451 in the first nine months of 2012 to $249,798 in the first nine months of 2013 due to decreased well and platform abandonment costs and the
effect of audit adjustments in the first nine months of 2013 as compared to the first nine months of 2012.

South
Timbalier 36/37 crude oil revenues decreased from $397,752 in the first nine months of 2012 to $321,347 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 3,200 barrels in the first nine months of 2013 from 3,494 barrels in the first nine months of
2012. The average crude oil price received decreased from $113.84 per barrel in the first nine months of 2012 to $100.42 per barrel in the first nine months of 2013. Gas revenues increased from
$27,428 in the first nine months of 2012 to $29,423 in the first nine months of 2013 due to an increase in the average natural gas price received from $3.00 per Mcf in the first nine months of 2012 to
$3.75 per Mcf in the first nine months of 2013. There was a decrease in natural gas volumes from 9,149 Mcf in the first nine months of 2012 to 7,842 Mcf in the first nine months of 2013. Capital
expenditures increased from $16,501 in the first nine months of 2012 to $62,287 in the first nine months of 2013. The costs in the first nine months of 2013 were primarily associated with the facility
improvements. Operating expenses increased from $24,961 in the first nine months of 2012 to $45,154 in the first nine months of 2013 due to workover repairs conducted during the first nine months of
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. Following repairs to fix the leak, limited
production resumed in July 2012. As a result of prior period adjustments, net crude oil revenues were $323,277 and net crude oil production was 4,322 barrels in the first nine months of 2013. Also as
a result of prior period adjustments, gas revenues were $23,930 and gas production was 4,858 Mcf in the first nine months of 2013. There were no meaningful revenues or production of oil or gas from
Eugene Island 342 in the first nine months of 2012. As the underlying interest in Eugene Island 339 is an overriding royalty interest, there were no capital or operating expenses recorded in the first
nine months of 2012 and 2013.

26

---





Including
the results of the working interest audit adjustment for Eugene Island 339 and the prior period adjustments for Eugene Island 342, crude oil and condensate revenues increased
$3,183,684, or 35%, to $12,227,599 in the first nine months of 2013 from $9,043,915 in the first nine months of 2012. Oil volumes during the first nine months of 2013 increased 56% to 128,989 barrels,
compared to 82,551 barrels of oil produced in the first nine months of 2012. The increase in volumes is due primarily to the working interest audit adjustment for Eugene Island 339 and, to a lesser
extent, the prior period adjustments for Eugene Island 342. The average price received for crude oil and condensate production decreased 13.5%, or $14.76, to $94.80 per barrel in the first nine months
of 2013 from $109.56 per barrel in the first nine months of 2012, excluding the impact of the working interest audit adjustments for Eugene Island 339 and prior period adjustments for Eugene Island
342.

Including
the results of the working interest audit adjustment for Eugene Island 339 and prior period adjustments for Eugene Island 342, gas revenues increased $1,822,975, or 608%, to
$2,122,915 in the first nine months of 2013 from $299,940 in the first nine months of 2012. Gas volumes during the first nine months of 2013 increased 107% to 220,971 Mcf, compared to 106,605 Mcf
produced in the first nine months of 2012. The increase in volumes is due primarily to the working interest audit adjustment for Eugene Island 339 and, to a lesser extent, the prior period adjustments
for Eugene Island 342. The average price received for natural gas production was $4.09 per Mcf in the first nine months of 2013 compared to $2.81 per Mcf in the first nine months of 2012, excluding
the impact from the working interest audit adjustments for Eugene Island 339 and prior period adjustments for Eugene Island 342. As a result of the adjustments, gas products revenue decreased
$491,370, or 1376%, to $(455,652) in the first nine months of 2013 from $35,718 in the first nine months of 2012. Due to prior period and it adjustments, gas products volumes during the first nine
months of 2013 decreased 858% to (275,698) gallons, compared to 36,366 gallons in the first nine months of 2012.

Capital
expenditures decreased by $4,042,194, or 93%, from $4,343,440 in the first nine months of 2012 to $301,246 in the first nine months of 2013. The higher amount of capital
expenditures during the first nine months 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 $10,825,743, or 71%, from $15,188,111 in the first nine months of 2012 to $4,362,368 in the first nine months of 2013. The decrease in operating expenses
is due primarily to less well and platform abandonment work being conducted at Eugene Island 339 in the first nine months of 2013 as compared to the first nine months of 2012.

The
Royalty Properties had undistributed net income of $9,231,249 in the first nine months of 2013 compared to net loss of $10,260,936 for the first nine months of 2012 due primarily to
the working interest audit adjustment for Eugene Island 339, the prior period adjustments for Eugene Island 342 and lower abandonment cost.

In
the first nine months of 2013, there were no funds released from or escrowed into the Special Cost Escrow account. As of September 30, 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.

27

---



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 Original 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. As of July 31, 2013, approximately $19.76 million of the estimated aggregate cost had been
incurred.

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.

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,

28

---



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 Original 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%. In May, 2013, Arena completed a third well pursuant to the Arena Agreement and production has commenced
from this well. With this drilling, completion and placing on production of the third well, Arena has satisfied its drilling and well completion obligations under the Arena Agreement as those
obligations relate to 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 for a scheduled tank replacement and production has slowly
returned thereafter. Production was shut-in on multiple occasions during 2012 and 2013 for various facility improvement projects during which time production has been temporarily impacted.

Production
from Eugene Island 342 effectively ceased in the first quarter of 2011 because a third party pipeline from the field was shut in due to a leak. Following repairs to fix the
leak, limited production resumed in July 2012 and production has improved during 2013.

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

29

---



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 attributable to the Trust during the
respective production periods attributable to the periods indicated. The following includes the effect of the working interest audit adjustment of Eugene Island 339 and the prior period adjustments
for Eugene Island 342. Net Proceeds due to the Trust are calculated for each three month period commencing on the first day of February, May, August and November.

Royalty Properties
Three Months
Ended September 30,(1)

Royalty Properties
Nine Months
Ended September 30,(1)2013

2012

2013

2012Crude oil and condensate (bbls)


45,954


29,143


128,989


82,551Natural gas and gas products (Mcfe)


35,578


40,440


175,020


111,801Crude oil and condensate average price, per bbl

$
102.71

$
105.79

$
94.80
(2)
$
109.56Natural gas average price, per Mcf (excluding gas products)

$
4.38
(3)
$
2.22

$
9.61

$
2.81Crude oil and condensate revenues

$
4,720,073

$
3,082,887

$
12,227,599

$
9,043,915Natural gas and gas products revenues


154,997


95,338


1,667,264


335,659Production expenses


(1,280,300
)

(4,267,426
)

(4,362,368
)

(15,188,111
)Capital expenditures


(61,134
)

(2,694,974
)

(301,246
)

(4,343,440
)Interest





(30,065
)




(108,960
)Undistributed net loss (income)(4)


(3,533,635
)

3,814,240


(9,231,249
)

10,260,937Refund of (provision for) Special Cost Escrow











Net Proceeds











Royalty interest


x20
%

x20
%

x20
%

x20
%Partnership share











Trust interest


x99.99
%

x99.99
%

x99.99
%

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

$


$


$


$



(1)Amounts
are based on production for the three- and nine-month period ended July 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 $105.38 per barrel.(3)Excluding
the adjustments, the average price was $4.09 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


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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.


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.

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

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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 (deficit). 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 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 September 30, 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
overriding royalty interest in the Royalty Properties. 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 overriding royalty interest exceed the proceeds of production from the Royalty Properties.

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Item 4.    Controls and Procedures.

Evaluation of disclosure controls and procedures.The Corporate Trustee maintains disclosure controls and procedures designed to ensure
that
information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within
the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the
Trust is accumulated and communicated by Chevron, as the Managing General Partner of the Partnership, and the Working Interest Owners to the Corporate Trustee of the Trust, and its employees who
participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

As
of the end of the period covered by this report, the Corporate Trustee carried out an evaluation of the Trust's disclosure controls and procedures. 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 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 September 30, 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 are not likely to be sufficient Net Proceeds distributed to the Trust for the foreseeable future to
enable the Trust to pay expenses on a current basis. The Trustees have taken certain actions on behalf of the Trust as permitted under the Trust Agreement, which could materially impact the Unit
holders.

The
Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. The Trust has not received a distribution of Net Proceeds
since December 2008, and there are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. On May 23, 2013, the Trust executed a demand promissory note
for $300,000 payable to The Bank of New York Mellon, N.A., an affiliate of the Corporate Trustee, acting as lender. Pursuant to the Trust Agreement, no distributions to Unit holders will be made until
the promissory note is paid in full.

In
addition to the promissory note, on October 31, 2013, the Partnership closed the sale of 25% of its remaining interests in the Original Royalty. The sale generated $1,200,000
in gross proceeds and the
Trust received a distribution of approximately $1,151,885, representing 99.99% of the net proceeds from the sale of $1,152,000. As a result of the October 31, 2013 sale and a sale in October
2011, the Partnership now holds a 60% interest in the Original Royalty (15% of 8/8ths), and thus the Partnership, assuming no further sales of the Royalty, will receive in the future only 60% of the
Net Proceeds if and when there are sufficient Net Proceeds for distribution on the Original Royalty.

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)


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SEC File or
Registration
Number

Exhibit
Number4(d)
*


Amendments to TEL Offshore Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)

0-06910

4(d)4(e)
*


Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for the year ended December 31, 1992 of TEL Offshore
Trust)

0-06910

4(e)10(a)
*


Purchase Agreement, dated as of December 7, 1984 by and between Tenneco Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore
Trust)

0-06910

10(a)10(b)
*


Consent Agreement, dated November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)

0-06910

10(b)10(c)
*


Assignment and Assumption Agreement, dated November 17, 1988, between Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of TEL
Offshore Trust)

0-06910

10(c)10(d)
*


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

0-06910

10(d)10(e)
*


Demand Promissory Note, dated as of May 23, 2013, between TEL Offshore Trust and The Bank of New York Mellon, N.A.

0-06920

10.131



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



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


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SIGNATURES

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

TEL OFFSHORE TRUSTBy:

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

/s/ MICHAEL J. ULRICH Michael J. Ulrich Vice President


Date:
November 14, 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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