PINX:TELOZ Tel Offshore Trust Quarterly Report 10-Q Filing - 6/30/2012

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, 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 June 30, 2012

Or

o

 

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 August 14, 2012, 4,751,510 Units of Beneficial Interest in TEL Offshore Trust were outstanding.

   



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, 2011 (the "2011 10-K") and such other factors as may be set forth from time to time in the Trust's filings with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to the Managing General Partner or the Trust or persons acting on behalf of the Managing General Partner or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.



PART I—FINANCIAL INFORMATION

Item 1.    Condensed Financial Statements.

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

 
  June 30,
2012
  December 31,
2011
 

Assets

             

Cash and cash equivalents

  $ 454,894   $ 944,917  

Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,249,222 and $28,248,147, respectively

    18,433     19,508  
           

Total assets

  $ 473,327   $ 964,425  
           

Liabilities and Trust Corpus

             

Distribution payable to Unit holders

  $   $  

Reserve for future Trust expenses

    454,894     944,917  

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

    18,433     19,508  
           

Total liabilities and Trust corpus

  $ 473,327   $ 964,425  
           


CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)

 
  Three Months
Ended June 30,
  Six Months
Ended June 30,
 
 
  2012   2011   2012   2011  

Royalty income

  $   $   $   $  

Interest income

    18     4     41     13  
                   

    18     4     41     13  

Decrease in reserve for future Trust expenses

    323,221     19,833     488,884     304,391  

General and administrative expenses

    (323,239 )   (19,837 )   (488,925 )   (304,404 )
                   

Distributable income

                 
                   

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

  $ .000000   $ .000000   $ .000000   $ .000000  
                   

Distributions per Unit (4,751,510 Units)

  $ .000000   $ .000000   $ .000000   $ .000000  
                   


CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS
(Unaudited)

 
  Three Months
Ended June 30,
  Six Months
Ended June 30,
 
 
  2012   2011   2012   2011  

Trust corpus, beginning of period

  $ 18,774   $ 21,913   $ 19,508   $ 22,495  

Distributable income

                 

Distribution payable to Unit holders

                 

Amortization of net overriding royalty interest

    (341 )   (727 )   (1,075 )   (1,309 )
                   

Trust corpus, end of period

  $ 18,433   $ 21,186   $ 18,433   $ 21,186  
                   

   

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

1



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

(1) Trust Organization

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

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

        The terms of the Trust Agreement, dated January 1, 1983 (as amended, the "Trust Agreement"), provide, among other things, that:

            (a)   the Trust is a passive entity and cannot engage in any business or investment activity or purchase any assets;

            (b)   the interest in the Partnership can be sold in part or in total for cash upon approval of a majority of the Unit holders;

            (c)   the Trustees, as defined below, can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge the assets of the Trust to secure payments of the borrowings. At June 30, 2012 and December 31, 2011, respectively, the reserve amount was $454,894 and $944,917;

            (d)   the Trustees will make cash distributions to the Unit holders in January, April, July and October of each year as discussed in Note 4; and

            (e)   the Trust will terminate upon the first to occur of the following events: (i) total future net revenues attributable to the Partnership's interest in the Royalty, as determined by independent petroleum engineers, as of the end of any year, are less than $2.0 million or (ii) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. Future net revenues attributable to the Royalty were estimated at approximately $11.5 million (unaudited) as of October 31, 2011. Such future net revenues do not include reserves attributable to Eugene Island 339 or any capital expenditures for any redevelopment of Eugene Island 339. However, such future net revenues do include the estimated total plugging and abandonment costs related to Eugene Island 339, with costs to the Royalty as of October 31, 2011 relating thereto estimated to be approximately $17.6 million. The $17.6 million of estimated plugging and abandonment costs included in the reserve report as of October 31, 2011 has been increased by Chevron to $18.7 million in March 2012, approximately $18.5 million of which had been incurred

2



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(1) Trust Organization (Continued)

    through April 30, 2012. Upon termination of the Trust, the Corporate Trustee will sell for cash all assets held in the Trust estate and make a final distribution to the Unit holders of any funds remaining, after all Trust liabilities have been satisfied.

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

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

(2) Basis of Accounting and Going Concern

        The accompanying unaudited financial information has been prepared by the Corporate Trustee. The accompanying financial information is prepared on a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America ("generally accepted accounting principles"). The Corporate Trustee and the Individual Trustees believe that the information furnished reflects all adjustments that are, in the opinion of the Trustees, necessary for a fair presentation of the results for the interim periods presented. Such adjustments are of a normal and recurring nature. The financial information should be read in conjunction with the financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2011.

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

3



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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

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

    (a)
    Royalty income from overriding royalty interest is recorded when received, including the effect of overtaken or undertaken positions and negative or positive adjustments, by the Corporate Trustee on the last business day of each calendar quarter. In addition, Royalty income includes amounts related to funds deposited or released from the Special Cost Escrow account—see (d);

    (b)
    Trust general and administrative expenses (which include the Trustee's fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid by the Trust rather than when incurred;

    (c)
    Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under generally accepted accounting principles, or GAAP;

    (d)
    The funds deposited or released from the Special Cost Escrow account are recorded at the time of payment or receipt. The Special Cost Escrow account is an account of the Working Interest Owners and is not reflected in the condensed financial statements of the Trust; and

    (e)
    Amortization of the investment in overriding royalty interest is calculated based on the units-of-production method. Such amortization is charged directly to Trust corpus and does not affect distributable income.

        This manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the Working Interest Owners. The condensed financial statements of the Trust differ from condensed financial statements prepared in accordance with GAAP, because, under such principles, Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

        The Trustees, including the Corporate Trustee, have no authority over, have not evaluated and make no statement concerning, the internal control over financial reporting of any of the Working Interest Owners.

        On the last business day of each calendar quarter prior to August 1, 2011, the Working Interest Owners were to pay to the Partnership 25% of the Net Proceeds (as defined below in Note 3) for the

4



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(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 sold 20% of the Royalty to a third party; as a result, on the last business day of each calendar quarter after August 1, 2011, the Working Interest Owners are to pay to the Partnership 20% of the Net Proceeds for the immediately preceding Quarterly Period. A Quarterly Period is each period of three months commencing on the first day of February, May, August and November. In turn, the Partnership distributes funds to its partners on the last business day of each calendar quarter. Cash distributions from the Trust are made in January, April, July and October of each year, and are payable to Unit holders of record as of the last business day of each calendar quarter. Thus, any cash conveyed to the Trust from the Royalty during the quarter ended June 30, 2012 would substantially represent the revenues and expenses from the Royalty Properties from February 2012 through April 2012. Similarly, any cash conveyed to the Trust from the Royalty during the quarter ended June 30, 2011 would substantially represent the revenues and expenses from the Royalty Properties from February 2011 through April 2011. However, there was no cash conveyed to the Trust from the Royalty Properties from either February 2012 through April 2012 or February 2011 through April 2012. The financial and operating information included in this Form 10-Q for the three months ended June 30, 2012 and June 30, 2011 represents financial and operating information with respect to the Royalty Properties for the immediately preceding months of February, March and April. Similarly, financial and operating information with respect to the Royalty Properties for the six months ended June 30, 2012 and June 30, 2011 represents financial and operating information with respect to the Royalty Properties for the immediately preceding months of November through April. Income from the Royalty is recorded by the Trust on a cash basis, when it is received by the Trust from the Partnership.

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

        Impairment of Investment in Overriding Royalty Interest—The Trust reviews overriding royalty interests in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss is recognized to write down the asset to its estimated fair value. Preparation of estimated expected future cash flows is inherently subjective and is based on

5



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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

the Corporate Trustee's best estimate of assumptions concerning expected future conditions. There were no write downs taken in the three or six months ended June 30, 2012.

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

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

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

        Special Cost Escrow account—The Special Cost Escrow account (see Note 5) is established for future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty 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 June 30, 2012, applicable to the Trust or its condensed financial statements.

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

(3) Net Overriding Royalty Interest

        On October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale of 20% of the Royalty. The sale generated $1,600,000 in gross proceeds and

6



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(3) Net Overriding Royalty Interest (Continued)

occurred as part of a formal auction process for the Royalty. The Trust received from the Partnership a distribution of approximately $1,485,851, representing 99.99% of the net proceeds from the sale of $1,486,000. The Trust will use such net proceeds solely for the payment of expenses of the Trust.

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

        The sale was made to the Purchaser on October 27, 2011, though the assignment of the 20% was effective as of August 1, 2011. The Purchaser initially required a minimum purchase of 25% of the Royalty. Pursuant to an Option Agreement, the Partnership has agreed with the Purchaser that if the Partnership elects to sell, or market for sale, any portion of the Royalty on or prior to December 31, 2012, the Purchaser will have the option to acquire such percentage interest, up to an additional 5% of the entire Royalty, for a sales price equivalent to the product of $80,000 times the percentage interest acquired. In order to exercise the option, the Purchaser would have to provide the Partnership notice of such exercise within 10 days following the Partnership's notice to the Purchaser of such proposed sale.

        The Royalty entitles the Trust to its share (99.99%) of 80% of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance, dated January 1, 1983, provides that the Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the Net Proceeds from their oil and gas properties for the period. Generally, "Net Proceeds" means the amounts received by the Working Interest Owners from the sale of minerals from the Royalty Properties less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and the Special Cost Escrow account. The Special Cost Escrow account is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not include amounts received by the Working Interest Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future delivery of gas.

        As of October 9, 2001, Chevron Corporation merged with Texaco Inc. and the Royalty Properties owned by Texaco Exploration and Production Inc. ("TEPI") were assigned to Chevron U.S.A. Inc. ("Chevron") on May 1, 2002. Crude oil sales from the Chevron and TEPI properties added together accounted for approximately 100% of crude oil revenues from the Royalty Properties for the three and six months ended June 30, 2012 and June 30, 2011. Sales to Chevron Corporation accounted for 100% of total gas revenues from the Royalty Properties for the three and six months ended June 30, 2012 and June 30, 2011.

7



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(3) Net Overriding Royalty Interest (Continued)

        The Trust's share of Royalty income was reduced by approximately $39,435 and $71,953, respectively, for each of the three months ended June 30, 2012 and June 30, 2011, and approximately $109,343 and $126,471, respectively, for each of the six months ended June 30, 2012 and June 30, 2011, 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 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.

        While oil and gas production at Ship Shoal 182 and 183 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, from historical levels, and the amount of expenditures incurred that are associated with such damages, including the expenditures required to plug and abandon the wells on Eugene Island 339 and, as currently expected, to redevelop the facility at Eugene Island 339. While Chevron has stated that it intends to redevelop Eugene Island 339, there is no obligation for Chevron to continue to pursue such redevelopment. There can be no assurance by Chevron or anyone else as to the actual timing for any future distributions to the Partnership from the Royalty, and there is no guarantee that any further distributions will be made. Future Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the operators of the Royalty Properties. In September 2011, Chevron informed the Trust that the

8



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(4) Distributions to Unit Holders (Continued)

estimate of the Trust'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 $15 million to approximately $16.5 million. As of the October 31, 2011 reserve report, the estimate of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased to approximately $17.6 million. In March 2012, Chevron informed the Trust that the estimate of the Royalty's net portion of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $17.6 million to approximately $18.7 million, approximately $18.5 million of which had been incurred through April 30, 2012, and without giving credit for an expected approximately $212,000 of insurance proceeds to be received by Chevron and to be allocated for the benefit of the Royalty with respect to 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 April 30, 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 $7.5 million, net to the entire Royalty ($6.0 million attributable to the Trust as of April 30, 2012. As of October 31, 2011, 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 $5.9 million, net to the entire Royalty ($4.7 million attributable to the Trust as of December 31, 2011). 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. Significant redevelopment costs will be incurred if Eugene Island 339 is redeveloped; however, Chevron has entered into a participation agreement with a third party whereby the third party has the right to earn an assignment of 65% of Chevron's working interest in the Eugene Island properties, and neither Chevron nor the Trust would, except in the event of any amendment or termination of the participation agreement, bear the cost of the redevelopment of Eugene Island 339. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this time, the ultimate outcome of these matters cannot be determined with any degree of certainty.

        For the three months ended June 30, 2012, the Trust had undistributed net loss of $531,875, representing the Trust's portion of the aggregate undistributed net loss of $2,659,642 associated with the Royalty Properties for the three months ended June 30, 2012. For the six months ended June 30, 2012, the Trust had undistributed net loss of $1,289,210, representing the Trust's portion of the undistributed net loss of $6,446,697 associated with the Royalty Properties for the six months ended June 30, 2012. The cumulative undistributed net loss for the Trust was $5,976,141 as of June 30, 2012. Undistributed net loss represents the amount of development and production costs associated with the

9



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(4) Distributions to Unit Holders (Continued)

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

(5) Special Cost Escrow Account

        The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on certain factors, including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. As of June 30, 2012, 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.

        During the first six months of 2012 and during 2011, there were no funds released from or deposited into the Special Cost Escrow account.

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

        The discussion of the terms of the Conveyance and Special Cost Escrow Account contained herein is qualified in its entirety by reference to the Conveyance.

        Deposits to the Special Cost Escrow Account will be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the

10



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(5) Special Cost Escrow Account (Continued)

estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made.

(6) Reserve For Future Trust Expenses

        The Trust generally maintains a cash reserve, equal to approximately three times the average annual expenses of the Trust during each of the then past three years, to provide for future administrative expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the Trust has not received sufficient Net Proceeds to maintain the reserve at such level. During the second quarter of 2012, the Trust decreased its reserve by $323,221, to pay current expenses, resulting in a reserve balance of $454,894 as of June 30, 2012, or approximately 50% of the average annual expenses of the Trust during the three-year period ended June 30, 2012. As of December 31, 2011, the reserve was $944,917 or 102% of the average annual expenses during the three year period ended December 31, 2011.

        There are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. There can be no assurance by Chevron or anyone else as to the actual timing for any future distributions to the Partnership from the Royalty, and there is no guarantee that any further distributions will be made. Absent the receipt of Net Proceeds or other actions being taken, at some time, the Trust will not have sufficient funds to pay the liabilities of the Trust. As such, the Trustees may take certain actions, discussed below, on behalf of the Trust as permitted under the Trust Agreement, which could materially impact the Unit holders.

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

        The Trust Agreement further provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders (a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

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

11



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (Continued)

(Unaudited)

(6) Reserve For Future Trust Expenses (Continued)

from the proceeds of such sale. Based on a recommendation from Chevron, as the Managing General Partner of the Partnership, Chevron marketed for sale by the Partnership the entire Royalty, while reserving the right to sell only a portion of the Royalty. Chevron engaged EnergyNet.com, Inc. to conduct the marketing process and the related auction for the Royalty, with the bids in the auction due on August 30, 2011. EnergyNet.com, Inc. is a FINRA-registered broker dealer that provides marketing services to the oil and gas industry.

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

        Based on the continuing expenses of the Trust and the lack of any distributions and any assurances as to the actual timing of any future distributions, on July 11, 2012, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell a portion of the Royalty so that the Trust will have sufficient funds to pay its liabilities. The Trustees have initiated contact with RNR Production to determine its interest in purchasing the additional five percent (5%) of the Royalty pursuant to an Option Agreement entered into between the Partnership and RNR Production in connection with the Partnership's previous sale of 20% of the Royalty to RNR Production. If RNR Production desires to purchase such additional five percent (5%) of the Royalty, it is anticipated that the Trust will request the Partnership to move forward with such sale as soon as practicable. If RNR Production does not desire to purchase the entire five percent (5%) of the Royalty, the Trustees will consider the costs and expenses of pursuing an alternative sale process. There can be no assurance that such a sale of interests in the Royalty will be consummated, or as to the terms, conditions and timing of such a sale of interests in the Royalty.

(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.

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

Liquidity and Capital Resources

        The Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at $11.5 million as of October 31, 2011. However, there are not likely to be sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable future. 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.

        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, although there were funds available for distribution given that there was some production from Eugene Island 339 and Ship Shoal 182/183 in August and September 2008. The Trust has not received a distribution of Net Proceeds since December 2008. Consequently, the Trust has not made a distribution to Unit holders for 14 consecutive quarters, or since January 9, 2009. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue to be severely impacted by reduced production, from historical levels, and the amount of expenditures incurred that are associated with such damages, including the expenditures required to plug and abandon the wells on Eugene Island 339. While Chevron has stated that it intends to redevelop Eugene Island 339, there is no obligation for Chevron to continue to pursue such redevelopment.

        The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike. Chevron is working on the plugging and abandonment of the existing wells, clearing debris and otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the fourth quarter of 2012. Chevron has informed the Corporate Trustee that Chevron presently intends to pursue the redevelopment of platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the BOEM in response to Chevron's submission to the BOEM of a program to restore production at Eugene Island 339; however, there is no obligation for Chevron to pursue such redevelopment. The costs for the redevelopment would be significant. Failure or inability to pursue such a redevelopment, and on the timeframes approved by the BOEM, could result in a loss of the lease. At this time, there can be no assurance that production will be restored at Eugene Island 339. Chevron has informed the Trust that, under a participation agreement with a third party, the third party holds the right to earn an assignment of 65% of Chevron's working interest in the Eugene Island 339 properties. Because Chevron's working interests will, upon any assignment as may be earned by the third party under such participation agreement, be reduced by 65%, the Royalty held by the Partnership with respect to such properties will, effective as of the date of any such assignment, be reduced proportionately. According to Chevron, as a result of any assignment that may be earned and delivered under such participation agreement, neither Chevron nor the Trust will, except in the event of any subsequent amendment(s) of the participation agreement, bear the cost of the

13


redevelopment of Eugene Island 339 under the terms of such participation agreement. See "—Operational Review" 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. See "—Operational Review" for a more detailed discussion of Ship Shoal 182/183.

        In addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. Chevron has been informed by the operator of West Cameron 643 that the operator submitted to the BOEM a request for an extension of the program to restore production but that such request was denied. Accordingly, the lease for West Cameron 643 expired on May 31, 2010. The field operator for East Cameron 371 has reported to Chevron that a review of the remaining reserves for East Cameron 371 has been conducted, and that the wells at East Cameron 371 have been depleted. The lease for East Cameron 371 expired on March 31, 2010. See "—Operational Review" for a more detailed discussion of West Cameron 643 and East Cameron 371.

        Future Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the operators of the Royalty Properties. Chevron has informed the Trustees that Chevron has reached settlements that provide Chevron with insurance proceeds associated with damages that Chevron's assets sustained from Hurricane Ike, and that the allocated portion thereof with respect to the Partnership's interest in Eugene Island 339, as a Royalty Property, is approximately $612,000. Chevron applied $400,000 thereof in the first quarter of 2011 and has stated that the remaining approximately $212,000 is to be received by Chevron and allocated to the Royalty upon completion of the abandonment work at Eugene Island, which is expected to occur in the fourth quarter of 2012. Chevron has stated that all such allocated insurance proceeds will be 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 2011, Chevron informed the Trust that the estimate of the aggregate cost to the Royalty to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $15 million to approximately $16.5 million. As of the October 31, 2011 reserve report, the estimate of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased to approximately $17.6 million. In March 2012, Chevron informed the Trust that the estimate of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $17.6 million to approximately $18.7 million, approximately $18.5 million of which had been incurred through April 30, 2012, without giving credit for an expected approximately $212,000 of insurance proceeds to be received by Chevron and to be allocated for the benefit of the Royalty with respect to Eugene Island 339. 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

14


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 April 30, 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 $7.5 million, net to the entire Royalty ($6.0 million attributable to the Trust as of April 30, 2012). As of October 31, 2011, 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 $5.9 million, net to the entire Royalty. In the fourth quarter of 2010, Chevron withdrew $4,304,894 from the Special Cost Escrow account of the Working Interest Owners (a reserve fund for certain costs) to cover expenses incurred in connection with the plugging and abandonment of Eugene Island 339, which served to reduce the amount by which production costs exceeded the proceeds from production; however, additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the terms of the Conveyance if, and when, Net Proceeds would otherwise be payable on the Royalty. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this time, the ultimate outcome of these various matters cannot be determined. See "—Operational Review."

        Substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major petroleum producing nations, as well as the regional supply and demand for oil and gas, worldwide political conditions, weather, industrial growth, conservation measures, competition, economic conditions generally and other variables.

        In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. In 1994, in anticipation of future periods when the cash received from the Royalty may not be sufficient for payment of Trust expenses, the Trust determined, in accordance with the Trust Agreement, to begin further increasing the Trust's cash reserve each quarter. In the first quarter of 1998, the Trust determined that the Trust's cash reserve was then sufficient to provide for future administrative expenses in connection with the winding up of the Trust. The Trust determined that a cash reserve equal to three times the average expenses of the Trust during each of the past three years was sufficient at such time to provide for future administrative expenses in connection with the winding up of the Trust.

        The Trust generally maintains a cash reserve, equal to approximately three times the average annual expenses of the Trust during each of the then past three years, to provide for future 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 second quarter of 2012, the Trust decreased its reserve by $323,221, to pay current expenses, resulting in a reserve balance of $454,894 as of June 30, 2012, or approximately 50% of the average annual expenses of the Trust during the three-year period ended June 30, 2012. As of December 31, 2011, the reserve was $944,917 or 102% of the average annual expenses during the three year period ended December 31, 2011.

15


        The Trustees of the Trust have previously asked Chevron if it would be willing to advance funds to the Partnership against future payments to the Partnership on the Royalty, particularly in light of Chevron's withdrawal of $4,304,894 from the Special Cost Escrow account in the fourth quarter of 2010. Chevron declined to make any such advance of funds, though orally offered to the Corporate Trustee in December 2010 to buy the Royalty for $0. As discussed under "—Operational Review", 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 has requested Chevron to pay any adjustments resulting from such audit directly to the Partnership; however, Chevron instead has stated that it will credit 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.

        In March 2011, the Trustees unanimously determined to suspend future payments of fees to the Trustees, until a date to be determined in the future by the Trustees. Such suspended fees were accrued as an expense of the Trust, but were not being paid on a current basis, until November 2011, when such fees were paid following receipt by the Trust of proceeds from the following described sale of a portion of the Royalty by the Partnership in late October 2011.

        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. However, there can be no assurance as to the terms and conditions of any such financing, or that any such financing can actually be obtained.

        The Trust Agreement provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders (a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

        On March 11, 2011, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell such portion, and only such portion, of the Royalty that would provide the Trust with a current distribution equal to $2,000,000 from the proceeds of such sale. Based on a recommendation from Chevron, as the Managing General Partner of the Partnership, Chevron marketed for sale by the Partnership the entire Royalty, while reserving the right to sell only a portion of the Royalty. Chevron engaged EnergyNet.com, Inc. to conduct the marketing process and the related auction for the Royalty, with the bids in the auction due on August 30, 2011. EnergyNet.com, Inc. is a FINRA-registered broker dealer that provides marketing services to the oil and gas industry.

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

16


the sale of $1,486,000. The Trust will use such net proceeds solely for the payment of expenses of the Trust.

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

        The sale was made to RNR Production on October 27, 2011, though the assignment of the 20% is effective as of August 1, 2011. RNR Production initially required a minimum purchase of 25% of the Royalty. Pursuant to an Option Agreement, the Partnership has agreed with RNR Production that if the Partnership elects to sell, or market for sale, any portion of the Royalty on or prior to December 31, 2012, RNR Production will have the option to acquire such percentage interest, up to an additional 5% of the entire Royalty, for a sales price equivalent to the product of $80,000 times the percentage interest acquired. In order to exercise the option, RNR Production would have to provide the Partnership notice of such exercise within 10 days following the Partnership's notice to RNR Production of such proposed sale.

        As discussed above, the Trust maintains a cash reserve to provide for future administrative expenses in connection with the winding up of the Trust. The Trust seeks to maintain a cash reserve of approximately three times the average annual expenses of the Trust. However, the Trust has not received sufficient Net Proceeds to maintain a cash reserve at such level and as of June 30, 2012, the cash reserve decreased to $454,894, or approximately 50% of the Trust's average annual expenses during the three-year period ended June 30, 2012.

        Based on the continuing expenses of the Trust and the lack of any distributions and any assurances as to the actual timing of any future distributions, on July 11, 2012, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell a portion of the Royalty so that the Trust will have sufficient funds to pay its liabilities. The Trustees have initiated contact with RNR Production to determine its interest in purchasing the additional five percent (5%) of the Royalty pursuant to the Option Agreement detailed above. If RNR desires to purchase such additional five percent (5%) of the Royalty, it is anticipated that the Trust will request the Partnership to move forward with such sale as soon as practicable. If RNR Production does not desire to purchase the entire five percent (5%) of the Royalty, the Trustees will consider the costs and expenses of pursuing an alternative sale process. There can be no assurance that such a sale of interests in the Royalty will be consummated, or as to the terms, conditions and timing of such a sale of interests in the Royalty.

        The accompanying condensed financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on the going concern basis assume the realization of assets and the settlement of liabilities in the normal course of business. The lack of Net Proceeds and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going concern. Certain potential alternatives available to the Trustees are described in Note 6 to the condensed financial statements. The condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty. See Notes 2 and 6 to the condensed financial statements.

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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, 2011 future net revenues attributable to the Trust's royalty interests were estimated at $11.5 million. Estimates of proved oil and gas reserves attributable to the Partnership's royalty interest are based on existing economic and operating conditions in effect at October 31, 2011 in order to correspond with distributions to the Trust. Such reserve study also indicates that approximately 39% of the future net revenues from the Royalty Properties are expected to be received by the Trust by October 31, 2013. The reserve study does not include reserves attributable to Eugene Island 339 or any capital expenditures for any redevelopment of Eugene Island 339. However, such reserve study does include the Trust's share of the estimated total plugging and abandonment costs related to Eugene Island 339. In March 2012, Chevron informed the Trust that the estimate of the Royalty's net portion of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $17.6 million to approximately $18.7 million, approximately $18.5 of which had been incurred through April 2012, and without giving credit for an expected approximately $212,000 of insurance proceeds to be received by Chevron and to be allocated for the benefit of the Royalty with respect to Eugene Island 339. Because the Trust will terminate in the event estimated future net revenues fall below $2.0 million, it would be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination of the Trust, the Trustees will sell for cash all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied. The estimates of future net revenues discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties present in estimating future net revenues for the Royalty Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed by DeGolyer and MacNaughton. In addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth above is qualified in its entirety by reference to the 2011 10-K. The Trust's Form 10-K is available at the website of the Securities and Exchange Commission ("SEC") at www.sec.gov or upon request from the Corporate Trustee.

Special Cost Escrow Account

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

18


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 three and six months ended June 30, 2012, there were no funds released or escrowed from the Special Cost Escrow account. As of June 30, 2012, $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 October 31, 2011 was approximately $5.9 million, net to the entire 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 2011, there were no funds released from or escrowed into the Special Cost Escrow account. As of June 30, 2012, $1,000 remained in the Special Cost Escrow account.

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

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

Three Months Ended June 30, 2012 and 2011

    Royalty Trust Comparison

        Royalty income was $0 for the three months ended June 30, 2012 and 2011 because there were no positive Net Proceeds attributable to the Royalty Properties due to damages inflicted to the Royalty Properties by Hurricane Ike in September 2008.

        General and administrative expenses for the Trust were $323,239 for the three months ended June 30, 2012 compared to $19,837 for the three months ended June 30, 2011. The increase is due primarily to the timing of the payment of expenses.

        The reserve for future Trust expenses decreased approximately $323,221 from March 31, 2012 to June 30, 2012 due to payments for Trust expenses.

        There was no distributable income for each of the three months ended June 30, 2012 and June 30, 2011 and therefore no distributions to unit holders.

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        For the three months ended June 30, 2012, the Trust had undistributed net loss of $531,875, representing the Trust's portion of the undistributed net loss of $2,659,642 associated with the Royalty Properties for the three months ended June 30, 2012. The cumulative undistributed net loss for the Trust was $5,976,141 as of June 30, 2012. 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.

    Underlying Properties Comparison

        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 $4,263,094 in the second quarter of 2011 to $1,879,116 in the second quarter of 2012, due to a decrease in net crude oil production from 40,800 barrels in the second quarter of 2011 to 16,578 barrels in the second quarter of 2012. The decrease in volumes was due to multiple shut ins for facility improvement projects during the second quarter of 2012. There was an increase in the average crude oil price received from $104.49 per barrel in the second quarter of 2011 to $113.35 per barrel for the same period in 2012. Gas revenues decreased from $164,686 in the second quarter of 2011 to $41,265 in the second quarter of 2012, due to a decrease in gas production from 41,042 Mcf in the second quarter of 2011 to 17,137 Mcf in the second quarter of 2012 also as a result of the shut ins during the second quarter of 2012. There was a decrease in average gas revenue price received from $4.01 per Mcf in the second quarter of 2011 to $2.41 per Mcf for the same period in 2012. Capital expenditures increased from $96,300 in the second quarter of 2011 to $1,338,059 in the second quarter of 2012 as a result of the costs associated with the facility improvement projects. Operating expenses increased from $738,331 in the second quarter of 2011 to $1,475,898 for the same period in 2012.

        Eugene Island 339 net crude oil revenues were $0 in the second quarter of 2011 and 2012 due to suspended drilling activity and, therefore, no production in the second quarter of 2012 and 2011. Gas revenues were $0 in the second quarter 2011 and 2012 also as a result of the suspended drilling and, therefore, no gas production during the second quarter of 2011 and 2012. Capital expenditures were $0 in the second quarter of 2011 and 2012. Operating expenses decreased from $4,156,686 in the second quarter of 2011 to $1,677,756 in the second quarter of 2012 due primarily to decreased well and platform abandonment costs in the second quarter of 2012 as compared to the second quarter of 2011.

        West Cameron 643 gas revenues were $0 in the second quarter of 2011 and in the second quarter of 2012. Gas volumes were 0 Mcf in the second quarter of 2011 and 2012. There was no actual gas production during the second quarter of 2011 and 2012 as a result of the field being shut-in following Hurricane Ike in September 2008. Operating expenses and capital expenditures were $0 in the second quarter of 2011 and 2012.

        East Cameron 371 crude oil revenues were $0 in the second quarter of 2011 and 2012 as a result of the field being shut-in following Hurricane Ike in September 2008. Production was 0 barrels in the

20


second quarter of 2011 and 2012. Gas revenues were $0 in the second quarter of 2011 and 2012 as a result of no gas volumes in the second quarter 2011 and 2012. Operating expenses and capital expenditures were $0 in the second quarter of 2011 and 2012.

        South Timbalier 36/37 crude oil revenues decreased from $135,875 in the second quarter of 2011 to $133,844 for the same period in 2012 due primarily to a decrease in crude oil production volumes to 1,132 barrels in the second quarter of 2012 from 1,310 barrels in the second quarter of 2011. The decrease in crude oil production was partially offset by an increase in the average crude oil price received from $103.75 per barrel in the second quarter of 2011 to $118.27 per barrel in the second quarter of 2012. Gas revenues decreased from $13,003 in the second quarter 2011 to $8,451 in the second quarter of 2012 due primarily to a decrease in the average natural gas price received. The average natural gas price received decreased from $4.31 per Mcf in the second quarter of 2011 to $2.80 per Mcf in the second quarter of 2012. There was a slight increase in natural gas volumes from 3,019 Mcf in the second quarter of 2011 to 3,023 Mcf in the second quarter of 2012. Capital expenditures decreased from $7,430 in the second quarter of 2011 to $3,490 in the second quarter of 2012 due primarily to decreased drilling work that was conducted during the second quarter of 2011. Operating expenses increased from $7,136 in the second quarter of 2011 to $7,337 in the second quarter of 2012.

        Crude oil and condensate revenues decreased $2,386,009, or 54%, to $2,012,960 in the second quarter of 2012 from $4,398,969 in the second quarter of 2011. Oil volumes during the second quarter of 2012 decreased 57% to 17,710 barrels, compared to 42,109 barrels of oil produced in the second quarter of 2011. The decrease in volumes is due primarily to the shut-ins for facility improvement projects at Ship Shoal 182/183 during the second quarter of 2012. The average price received for crude oil and condensate increased 8%, or $9.19, to $113.66 per barrel in the second quarter of 2012 from $104.47 per barrel in the second quarter of 2011.

        Gas revenues decreased $127,973, or 72%, to $49,716 in the second quarter of 2012 from $177,689 in the second quarter of 2011. Gas volumes during the second quarter of 2012 decreased 54% to 20,159 thousand cubic feet ("Mcf"), compared to 44,061 Mcf produced in the second quarter of 2011. The decrease in volumes is due primarily to the shut-ins for facility improvement projects at Ship Shoal 182/183 during the second quarter of 2012. The average price received for natural gas was $2.47 per Mcf in the second quarter of 2012 compared to $4.03 per Mcf in the second quarter of 2011. Gas products revenue decreased $3,957, or 35%, to $7,244 in the second quarter of 2012 from $11,201 in the second quarter of 2011. Gas products volumes during the second quarter of 2012 decreased 2% to 7,571 gallons, compared to 7,731 gallons in the second quarter of 2011.

        Capital expenditures increased by $1,237,819, or 1,197%, from $103,370 in the second quarter of 2011 to $1,341,549 in the second quarter of 2012. The higher amount of capital expenditures during the second quarter of 2012 relate primarily to the facility improvement projects at Ship Shoal 182/183 during the second quarter of 2012.

        Production expenses decreased by $1,831,800, or 64.7%, from $5,189,965 in the second quarter of 2011 to $3,358,165 in the second quarter of 2012. The decrease in operating expenses is due primarily to less well and platform abandonment work being conducted at Eugene Island 339 in the second quarter of 2012 as compared to the second quarter of 2011. Reflected within the production expenses are management fees to Chevron, as Managing General Partner of the Partnership, of $287,712 and $197,174 for the second quarter of 2011 and the second quarter of 2012, respectively.

21


        The Royalty Properties had undistributed net loss of $2,659,642 in the second quarter of 2012 compared to $725,568 for the second quarter of 2011.

        In the second quarter of 2012, there were no funds released from or escrowed into the Special Cost Escrow account. As of June 30, 2012, $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.

        In the second quarter of 2011, there were no funds released from or escrowed into the Special Cost Escrow account. As of June 30, 2011, $1,000 remained in the Special Cost Escrow account.

Six Months Ended June 30, 2012 and 2011

    Royalty Trust Comparison

        Royalty income was $0 for the six months ended June 30, 2012 and 2011 because there were no positive Net Proceeds attributable to the Royalty Properties due to damages inflicted to the Royalty Properties by Hurricane Ike in September 2008.

        General and administrative expenses for the Trust were $488,925 for the six months ended June 30, 2012 compared to $304,404 for the six months ended June 30, 2011. The decrease is due primarily to the timing of the payment of expenses.

        The reserve for future Trust expenses decreased approximately $488,884 from December 31, 2011 to June 30, 2012 due to payments for Trust expenses.

        There was no distributable income for each of the six months ended June 30, 2012 and June 30, 2011 and therefore no distributions to unit holders.

        For the six months ended June 30, 2012, the Trust had undistributed net loss of $1,289,210, representing the Trust's portion of the undistributed net loss of $6,446,697 associated with the Royalty Properties for the six months ended June 30, 2012. The cumulative undistributed net loss for the Trust was $5,976,141 as of June 30, 2012. 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.

    Underlying Properties Comparison

        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.

22


        Ship Shoal 182/183 crude oil revenues decreased from $6,965,004 in the first six months of 2011 to $5,683,060 in the same period in 2012, due primarily to a decrease in net crude oil production from 72,092 barrels in the first six months of 2011 to 51,007 in the same period of 2012. The decrease in volumes was due to multiple shut ins for facility improvement projects during the second quarter of 2012. The average crude oil price increased from $96.61 per barrel in the first six months of 2011 to $111.42 per barrel for the same period in 2012. Gas revenues decreased from $321,832 in the first six months of 2011 to $194,403 in the same period of 2012. Gas production decreased from 80,605 Mcf in the first six months of 2011 to 62,004 Mcf in the same period of 2012. The natural gas sales price was $3.99 per Mcf in the first six months of 2011 compared to $3.14 per Mcf in the first six months of 2012. Capital expenditures increased from $632,270 in the first six months of 2011 to $1,643,602 in the same period of 2012, as a result of the costs associated with the facility improvement projects. Due to the same reason, operating expenses also increased from $1,894,690 in the first six months of 2011 to $2,316,838 for the same period in 2012.

        Eugene Island 339 net crude oil revenues were $0 in the first six months of 2011 and in 2012. Production was 0 barrels in the first six months of 2011 and 2012. Gas revenues were $0 in the first six months 2011 and 2012. Production was 0 Mcf in the first six months of 2011 and 2012. Capital expenditures were $0 in the first six months of 2011 and $(7,532) in the first six months of 2012. Operating expenses increased from $6,704,494 in the first six months of 2011 to $8,042,661 in the same period in 2012, due primarily to more well and platform abandonment work being conducted in the first six months of 2012 as compared to the first six months of 2011.

        West Cameron 643 gas revenues were $0 in the first six months of 2011 and 2012. Gas volumes were 0 Mcf in the first six months of 2011 and 2012. There was no actual gas production during the first six months of 2011 and 2012 as a result of the field being shut-in following Hurricane Ike in September 2008. Operating expenses were $0 for the first six months of 2011 and 2012, and capital expenditures were $0 for the first six months of 2011 and 2012, as the field was shut-in after Hurricane Ike in September 2008 as a result of damages to a third-party transporter's pipeline.

        East Cameron 371 crude oil revenues were $0 for the first six months of 2011 and 2012 as a result of the field being shut-in following Hurricane Ike in September 2008. Production was 0 barrels in the first six months of 2011 and 2012. Gas revenues were $0 for the first six months of 2011 and 2012 as a result of no volumes in the first six months of 2011 and 2012. Capital expenditures were $0 in the first six months of 2011 and 2012. Operating expenses were $0 in the first six months of 2011 and 2012.

        South Timbalier 36/37 crude oil revenues increased from $241,061 in the first six months of 2011 to $277,968 for the same period in 2012 due primarily to an increase in the average crude oil price received from $94.98 per barrel in the first six months of 2011 to $115.78 per barrel for the same period in 2012. This increase was partially offset by a decrease in crude oil production volumes to 2,401 barrels in the first six months of 2012 from 2,538 barrels in the first six months of 2011. Gas revenues decreased from $24,207 in the first six months of 2011 to $20,382 in the first six months of 2012. The natural gas sales price was $4.11 per Mcf in the first six months of 2011 compared to $3.30 per Mcf in the first six months of 2012. There was an increase in natural gas volumes from 5,883 Mcf in the first six months of 2011 to 6,172 Mcf in the first six months of 2012. Capital expenditures decreased from $33,964 in the first six months of 2011 to $12,397 in the first six months of 2012 due primarily to less drilling work that conducted during the first six months of 2012 compared to the same period in 2011. Operating expenses decreased from $16,353 in the first six months of 2011 to $14,472 in the first six months of 2012.

23


        Crude oil and condensate revenues decreased $1,245,036, or 17%, to $5,961,028 in the first six months of 2012 as compared to $7,206,064 for the same period in 2011, due primarily to decreased oil volumes. Oil volumes decreased 28% to 53,408 barrels in the first six months of 2012 from 74,629 barrels in the first six months of 2011. The decrease in volumes is due primarily to the shut-ins for facility improvement projects at Ship Shoal 182/183 during the second quarter of 2012. The average price received for crude oil and condensate increased 15%, or $15.05, to $111.61 per barrel in the first six months of 2012 from $96.56 per barrel in the first six months of 2011.

        Gas revenues decreased $131,255, or 37%, to $214,785 in the first six months of 2012 from $346,040 for the same period in 2011. Gas volumes decreased 21% to 68,175 Mcf in the first six months of 2012 from 86,488 Mcf for the same period in 2011. The decrease in volumes is due primarily to the shut-ins for facility improvement projects at Ship Shoal 182/183 during the second quarter of 2012. The average price received for natural gas decreased 21%, or $0.85, to $3.15 per Mcf in the first six months of 2012 from $4.00 per Mcf in the same period of 2011. Gas products revenue decreased $3,410, or 11%, to $25,535 in the first six months of 2012 from $28,945 in the same period of 2011, primarily due to a decrease in the average price received of $0.23, or 16%, to $1.15 per gallon in the first six months of 2012 from $1.38 per gallon in the same period of 2011. This decrease was partially offset by an increase in production volume of 1,446 gallons, or 6%, to 22,298 gallons in the first six months of 2012 from 20,852 gallons in the same period of 2011.

        Capital expenditures increased $982,231, or 147%, from $666,235 in the first six months of 2011 to $1,648,466 in the same period of 2012. The higher amount of capital expenditures during the second quarter of 2012 and relate primarily to the facility improvement projects at Ship Shoal 182/183 during the second quarter of 2012.

        Production expenses decreased by $1,799,263, or 20%, from $9,121,421 in the first six months of 2011 to $10,920,684 in the first six months of 2012, due primarily to increased well and platform abandonment work being conducted at Eugene Island 339 in the second quarter of 2012 as compared to the second quarter of 2011. Reflected within the production expenses are management fees to Chevron, as Managing General Partner of the Partnership, of $505,885 and $546,714 for the first six months of 2011 and the first six months of 2012, respectively.

        The Royalty Properties had undistributed net loss of $6,446,696 for the six months ended June 30, 2012.

        In the first six months of 2012 and 2011, no funds were released or escrowed from the Special Cost Escrow account.

Operational Review

        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

24


41% of such revenues for the nine months ended September 30, 2008. Based on a prior year reserve study prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants, Eugene Island 339 accounted for approximately 34% of the total future net revenues attributable to the Partnership's interest in the Royalty as of October 31, 2007. Chevron is still working on the plugging and abandonment of the existing wells, clearing debris and otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the fourth quarter of 2012. In September 2011, Chevron informed the Trust that the estimate of the aggregate cost to the Royalty to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $15 million to approximately $16.5 million. As of the October 31, 2011 reserve report, the estimate of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased to approximately $17.6 million. In March 2012, Chevron informed the Trust that the estimate of the aggregate cost to the Royalty to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $17.6 million to approximately $18.7 million, approximately $18.5 million of which had been incurred through April 30, 2012, without giving credit for an expected approximately $212,000 of insurance proceeds to be received by Chevron and to be allocated for the benefit of the Royalty with respect to Eugene Island 339.

        Generally, if production ceases from an outer continental shelf lease, like that for Eugene Island 339, production must be restored or drilling operations must commence within 180 days of the cessation 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. Chevron, as the operator of Eugene Island 339, sought and obtained an SOP for Eugene Island 339 for the period from December 1, 2010 through October 31, 2011. Chevron had previously sought and obtained an SOP providing for the staged redevelopment of Eugene Island 339 and the adjacent lease, Eugene Island 338 (which is not a Royalty Property), as a single development project, contingent upon meeting certain obligations established in the SOP. The initial SOP extended the lease on Eugene Island 339 until November 30, 2010. A subsequent SOP extended the lease from December 1, 2010 through October 31, 2011, as long as certain SOP milestones were met. The first milestone, "issue Jacket and Pile Material Order (MTO) Drawings to fabrication contractor," due prior to April 30, 2011, was met and Chevron so informed the BOEM. The second milestone, "continuation of offshore deck refurbishment," due prior to May 30, 201, was met and Chevron so informed the BOEM. Additional SOP milestones included a report on deck refurbishment due prior to August 30, 2011, and commencement of jacket and pile fabrication prior to October 30, 2011, both of which were also met. Chevron is required to provide the BOEM with periodic updates on the progress of the redevelopment of Eugene Island and to meet each of the SOP activity schedule deadlines to maintain the SOP. The second SOP (December 1, 2010 through October 31, 2011) expired on October 31, 2011. A third SOP was requested and was granted covering the period of time from October 31, 2011, through August 31, 2012. The third SOP requires meeting development and construction milestones prior to August 31, 2012, with the restoration of production in October 2012. An application for a fourth SOP will be required to cover the period of time from August 31, 2012 through October 2012. Chevron has stated it intends to redevelop Eugene Island 338 and 339, and has met the requirements set forth in the first SOP and in the second SOP; however, there is no assurance that a subsequent

25


SOP will be sought or, if sought, approved by the BOEM. Likewise, there is no obligation upon Chevron to continue to pursue the redevelopment of Eugene Island 338 and 339.

        In December 2009, Chevron entered into a participation agreement with a third party to assist in the redevelopment of Eugene Island 338 and 339. The redevelopment plan provided that three wells were to be drilled from a common open water location in Eugene Island 338 in the second quarter of 2010. The first well of the three-well drilling program had been drilled; however, drilling activity was suspended and the drilling rig moved off location in July 2010. Chevron's inability to obtain related drilling permits in a timely basis under the new guidelines issued by the BOEM on June 8, 2010, following the oil spill in the U.S. Gulf of Mexico related to the sinking of the Deepwater Horizon drilling rig, pursuant to Notice to Lessees No. 2010-N05, "Increased Safety Measures for Energy Development on the OCS", caused the parties to such participation agreement to revise and amend the participation agreement. The revised redevelopment plan provides for setting a platform at Eugene Island 338 and drilling wells into Eugene Island 339 and Eugene Island 338 from such platform. The revised redevelopment plan retains the original estimate for first production from Eugene Island 339 of the fourth quarter of 2012.

        By letter dated May 9, 2011, Chevron informed the Trust that, under such participation agreement with the third party, the third party holds the right to earn an assignment of 65% of Chevron's working interest in the Eugene Island 339 properties. 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. Because Chevron's working interests will, upon any assignment as may be earned under such participation agreement, be reduced by 65%, the Royalty held by the Partnership with respect to such properties will, effective as of the date of such assignment, be reduced proportionately. According to Chevron, as a result of any assignment that may be earned and delivered under such participation agreement, neither Chevron nor the Trust will, except in the event of any subsequent amendment(s) of the participation agreement, bear the cost of the redevelopment of Eugene Island 339 under the terms of such participation agreement. Chevron and the Trust will bear the proportionately reduced post-redevelopment costs incurred for each Eugene Island 339 Royalty Property.

        Restoration of production at Eugene Island 338 and 339 is a complex process, requires various governmental permits, and cannot be assured at this time. The costs for the redevelopment project would be significant. Failure or inability to pursue such a redevelopment, or to satisfy the activity schedule approved by the BOEM, could result in a loss of the lease covering Eugene Island 339. At this time, there is and can be no assurance that each activity schedule date will be met or that an additional SOP will be approved by the BOEM or that production will be restored at Eugene Island 339. Additionally, the Trust cannot predict at this time the further impact that the changes in regulatory requirements resulting from the oil spill in the U.S. Gulf of Mexico related to the sinking of the Deepwater Horizon drilling rig may have on the redevelopment of Eugene Island 339.

26


        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.

        In addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. Chevron, as the Managing General Partner of the Partnership, understands that, as a result of the cessation of production at West Cameron 643 due to the damages inflicted by Hurricane Ike to a third-party transporter's pipeline, Hilcorp submitted to the BOEM a program to restore production at West Cameron 643 and such request was granted. The approval by the BOEM expired by its terms on May 31, 2010, and Chevron has been informed by Hilcorp that it submitted to the BOEM a request for an extension but that such request was denied. Accordingly, the lease for West Cameron 643 expired on May 31, 2010. Chevron has been informed by Hilcorp that it is in the process of plugging and abandoning the wells at West Cameron 643, which is expected to be completed by July 2012. The field operator for East Cameron 371 has reported to Chevron that a review of the remaining reserves for East Cameron 371 has been conducted, and that the wells at East Cameron 371 have been depleted. The lease for East Cameron 371 expired on March 31, 2010 and field abandonment work, including the related wells, equipment platforms and any field infrastructure, remains to be completed.

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

27


Overview of Production, Prices and Royalty Income

        The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas recorded by the Working Interest Owners for the Royalty Properties, as well as the Working Interest Owners' calculations of the Net Proceeds and Royalties paid to the Trust during the periods indicated. 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 June 30,(1)
  Royalty Properties Six
Months Ended June 30,(1)
 
 
  2012   2011   2012   2011  

Crude oil and condensate (bbls)

    17,710     42,109     53,408     74,629  

Natural gas and gas products (Mcfe)

    21,241     45,165     71,361     89,466  

Crude oil and condensate average price, per bbl

  $ 113.66   $ 104.47   $ 111.61   $ 96.56  

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

  $ 2.47   $ 4.03   $ 3.15   $ 4.00  

Crude oil and condensate revenues

  $ 2,012,960   $ 4,398,969   $ 5,961,028   $ 7,206,064  

Natural gas and gas products revenues

    56,961     188,889     240,321     374,984  

Production expenses

    (3,358,165 )   (5,189,965 )   (10,920,685 )   (9,121,422 )

Capital expenditures

    (1,341,549 )   (103,730 )   (1,648,466 )   (666,235 )

Interest

    (29,849 )   (19,731 )   (78,895 )   (43,388 )

Undistributed net loss (income)(2)

    2,659,642     725,568     6,446,697     2,243,681  

Refund of (provision for) Special Cost Escrow

                6,316  
                   

Net Proceeds(3)

                 

Royalty interest

    x20 %   x25 %   x20 %   x25 %
                   

Partnership share

                 

Trust interest

    x99.99 %   x99.99 %   x99.99 %   x99.99 %
                   

Trust share of Royalty Income(4)

  $   $   $   $  
                   

(1)
Amounts are based on actual production for the three- and six- month period ended April 30 of each year, respectively.

(2)
Undistributed net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. Undistributed net income represents positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners.

(3)
The Net Proceeds with respect to Hilcorp's ownership of West Cameron 643 are calculated separately from the determination of Net Proceeds with respect to the other Royalty Properties. Similarly, the Net Proceeds with respect to ERT's ownership of East Cameron 371 are calculated separately from the determination of Net Proceeds with respect to the other Royalty Properties. No further Net Proceeds are expected with respect to these two properties; and any excess

28


    Production Costs associated with these properties are not expected to be taken into account with respect to the calculation of Net Proceeds with respect to the other Royalty Properties.

(4)
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 generally accepted accounting principles, or 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:

    (a)
    Royalty income from overriding royalty interest is recorded when received, including the effect of overtaken or undertaken positions and negative or positive adjustments, by the Corporate Trustee on the last business day of each calendar quarter. In addition, Royalty income includes amounts related to funds deposited or released from the Special Cost Escrow account—see (d);

    (b)
    Trust general and administrative expenses (which include the Trustee's fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid by the Trust rather than when incurred;

    (c)
    Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under generally accepted accounting principles, or GAAP;

    (d)
    The funds deposited or released from the Special Cost Escrow account are recorded at the time of payment or receipt. The Special Cost Escrow account is an account of the Working Interest Owners and is not reflected in the condensed financial statements of the Trust; and

    (e)
    Amortization of the investment in overriding royalty interest is calculated based on the units-of-production method. Such amortization is charged directly to Trust corpus and does not affect distributable income.

        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 generally accepted accounting principles, because, under such principles, Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

        The 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

29


realization of assets and the settlement of liabilities in the normal course of business. The lack of Net Proceeds and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going concern. Certain potential alternatives available to the Trustees are described in Note 6 to the condensed financial statements. The condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty. See Notes 2 and 6 to the condensed financial statements.

        The Trustees, including the Corporate Trustee, have no authority over, have not evaluated and make no statement concerning, the internal control over financial reporting of any of the Working Interest Owners.

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

        Impairment of Investment in Overriding Royalty Interest.    The Trust reviews 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 June 30, 2012 applicable to the Trust or its condensed financial statements.

Off-Balance Sheet Arrangements

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

Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

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

30


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

Item 4.    Controls and Procedures.

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

        As of the end of the period covered by this report, the Corporate Trustee carried out an evaluation of the Trust's disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Corporate Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

        Due to the contractual arrangements of (i) the Trust Agreement, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding information furnished by the Working Interest Owners, the Trustees rely on (A) information provided by the Working Interest Owners, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, (B) information from the Managing General Partner of the Partnership, including information that is collected from the Working Interest Owners, and (C) conclusions and reports regarding reserves by the Trust's independent reserve engineers. See Item 1A. Risk Factors "—The Trustees and the Unit holders have no control over the operation or development of the Royalty Properties and have little influence over operation or development" and "The Trustees rely upon the Working Interest Owners and Managing General Partner for information regarding the Royalty Properties" in the 2011 Form 10-K for a description of certain risks relating to these arrangements and reliance on and applicable adjustments to operating information when reported by the Working Interest Owners to the Corporate Trustee and recorded in the Trust's results of operation.

        Changes in Internal Control Over Financial Reporting.    During the three months ended June 30, 2012, 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.

31



PART II—OTHER INFORMATION

Item 1A.    Risk Factors.

        The Trust continues to utilize its cash reserves to pay expenses, and there are not likely to be 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. The Trust continues to utilize its cash reserves to pay expenses; however, as of June 30, 2012, those reserves were approximately 50% of the average annual expenses of the Trust during the three-year period ended June 30, 2012.

        Based on the continuing expenses of the Trust and the lack of any distributions and any assurances as to the actual timing of any future distributions, on July 11, 2012, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell a portion of the Royalty so that the Trust will have sufficient funds to pay its liabilities. The Trustees have initiated contact with RNR Production to determine its interest in purchasing the additional five percent (5%) of the Royalty pursuant to the Option Agreement detailed above. If RNR Production desires to purchase such additional five percent (5%) of the Royalty, it is anticipated that the Trust will request the Partnership to move forward with such sale as soon as practicable. If RNR Production does not desire to purchase the entire five percent (5%) of the Royalty, the Trustees will consider the costs and expenses of pursuing an alternative sale process. However, there can be no assurance that such a sale of interests in the Royalty will be consummated, or as to the terms, conditions and timing of such a sale of interests in the Royalty. See "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" under Item 2 of this Form 10-Q.

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
Number
  4(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)

32


 
   
   
  SEC File or
Registration
Number
  Exhibit
Number
  4(b )*   Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)   0-06910   4(b)

 

4(c

)*


 

Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)

 

0-06910

 

4(c)

 

4(d

)*


 

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

 

0-06910

 

4(d)

 

4(e

)*


 

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

 

0-06910

 

4(e)

 

10(a

)*


 

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

 

0-06910

 

10(a)

 

10(b

)*


 

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

 

0-06910

 

10(b)

 

10(c

)*


 

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

 

0-06910

 

10(c)

 

10(d

)*


 

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

 

0-06910

 

10(d)

 

31

 


 

Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 

 

 

 

 

32

 


 

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

 

 

 

 

33



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 TRUST

 

 

By:

 

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

 

 

By:

 

/s/ MIKE ULRICH

Mike Ulrich
Vice President

Date: August 14, 2012

        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.

34




QuickLinks

NOTE REGARDING FORWARD-LOOKING STATEMENTS
PART I—FINANCIAL INFORMATION
TEL OFFSHORE TRUST CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (Unaudited)
CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (Unaudited)
CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (Unaudited)
TEL OFFSHORE TRUST NOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited)
PART II—OTHER INFORMATION
SIGNATURES

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