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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-K

Commission File Number 0-6910

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

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

          Securities registered pursuant to Section 12(b) of the Act:

          Securities registered pursuant to Section 12(g) of the Act:

Units of Beneficial Interest
(Title of class)

          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý.

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý.

          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 Website, 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 proceeding 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

          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.

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

          The aggregate market value of the 4,751,510 Units of Beneficial Interest in TEL Offshore Trust held by non-affiliates as of the last business day of the registrant's most recently completed second fiscal quarter was $6,842,174 based on a June 30, 2011 closing sales price of $1.44.

          Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

          As of March 29, 2012, there were 4,751,510 Units of Beneficial Interest in TEL Offshore Trust outstanding.

Documents Incorporated By Reference: None

   

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Note Regarding Forward-Looking Statements

        This Annual Report on Form 10-K, or this Form 10-K, 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-K are forward-looking statements. Although the Managing General Partner of the Partnership (as defined below) has advised the Trust that the Managing General Partner believes that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-K, including without limitation in conjunction with the forward-looking statements included in this Form 10-K. Risks factors that may affect actual results and Trust distributions include, without limitation:

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the Trust's utilization of its cash reserves to pay expenses and the lack of net proceeds received by the Trust;



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commodity price fluctuations;



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uncertainty of estimates of oil and gas production;



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uncertainty of future production and development costs;



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operating risks for Working Interest Owners, including drilling and environmental risks;



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delays and costs in connection with repairs and replacements of hurricane-damaged facilities and pipelines;



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regulatory changes;



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decisions by and at the discretion of Working Interest Owners not to perform additional development projects, not to replace hurricane-damaged facilities, or to abandon properties; and



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uncertainties inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures.

        Should any event or circumstances contemplated by the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should any material underlying assumptions prove incorrect, actual results may differ materially from future results expressed or implied by the forward-looking statements. All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. See "Item 1A—Risk Factors" below in this Form 10-K for a summary description of principal risk factors.

PART I

Item 1.    Business.

DESCRIPTION OF THE TRUST

General

        The TEL Offshore Trust, which we refer to herein as the "Trust", was created under the laws of the State of Texas in 1983 and maintains its offices at the office of The Bank of New York Mellon Trust Company, N.A., whom we refer to as the "Corporate Trustee", 919 Congress Avenue, Austin, Texas 78701. The telephone number of the Corporate Trustee is 1-800-852-1422. The Bank of New York Mellon Trust Company, N.A. 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 Mellon Trust Company acquired substantially all of JPMorgan Chase's corporate trust business. JPMorgan Chase

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Bank was formerly known as The Chase Manhattan Bank and is the successor by mergers to the original corporate trustee, Texas Commerce Bank National Association. Gary C. Evans, Thomas H. Owen, Jr. and Jeffrey S. Swanson serve as individual trustees of the Trust and are referred to herein as the "Individual Trustees". The Individual Trustees and the Corporate Trustee may be referred to hereinafter collectively as the "Trustees."

        The Corporate Trustee does not maintain a website for filings by the Trust with the U.S. Securities and Exchange Commission, which we refer to herein as the "SEC". Electronic filings by the Trust with the SEC are available free of charge through the SEC's website at www.sec.gov and at www.businesswire.com/cnn/tel-offshore.htm. The Trust will also provide paper copies of its recent filing free upon request to the Trustee.

        The principal asset of the Trust consists of a 99.99% interest in the TEL Offshore Trust Partnership, which we refer to herein as the "Partnership". Chevron U.S.A., Inc., or "Chevron", owns the remaining .01% interest in the Partnership. Until October 27, 2011, the Partnership owned 100% of an overriding royalty interest, or "Royalty", where the entire Royalty is equivalent to a 25% net profits interest, in certain oil and gas properties, which we refer to herein as the "Royalty Properties", located offshore Louisiana. On October 27, 2011, but effective as of August 1, 2011, the Partnership consummated a sale to a third party of 20% of the Royalty for $1,600,000 in gross proceeds. The Trust received a distribution from the Partnership of approximately $1,485,851, representing 99.99% of the net proceeds from the sale of $1,486,000. After the sale, the Partnership now owns 80% of the Royalty.

        On October 31, 1986, Tenneco Exploration Ltd. ("Exploration I") was dissolved and the oil and gas properties of Exploration I were distributed to Tenneco Oil Company ("Tenneco") subject to the Royalty. Tenneco, who was then serving as the Managing General Partner of the Partnership, assumed the obligations of Exploration I, including its obligations under the instrument conveying the Royalty to the Partnership (the "Conveyance"). The dissolution of Exploration I had no impact on future cash distributions to holders of units of beneficial interest in the Trust.

        On November 18, 1988, Chevron acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco, including all of the Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as the Working Interest Owner and Managing General Partner of the Partnership. Chevron also assumed Tenneco's obligations under the Conveyance.

        On October 30, 1992, PennzEnergy Company ("PennzEnergy") (which merged with and into Devon Energy Production Company L.P. effective January 1, 2000) acquired certain oil and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by PennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of such acquisition, PennzEnergy replaced Chevron as the Working Interest Owner of such properties on October 30, 1992. PennzEnergy also assumed Chevron's obligations under the Conveyance with respect to these properties.

        On December 1, 1994, Texaco Exploration and Production Inc. ("TEPI") acquired two of the Royalty Properties from Chevron. The Royalty Properties acquired by TEPI were West Cameron 643 and East Cameron 371. As a result of such acquisitions, TEPI replaced Chevron as the Working Interest Owner of such properties on December 1, 1994. TEPI also assumed Chevron's obligations under the Conveyance with respect to these properties.

        On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco Production Company ("Amoco") acquired the Eugene Island 367 property from PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced PennzEnergy as the Working Interest Owners of the East Cameron 354 and Eugene Island 367 properties, respectively, on October 1, 1995 and also assumed PennzEnergy's obligations under the Conveyance with respect to these properties.

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        Effective January 1, 1998, Energy Resource Technology, Inc. ("ERT") acquired the East Cameron 354 property from SONAT. As a result of such acquisition, ERT replaced SONAT as the Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed SONAT's obligations under the Conveyance with respect to such property. In October 1998, Amerada Hess Corporation ("Amerada") acquired the East Cameron 354 property from ERT effective January 1, 1998. As a result of such acquisition, Amerada replaced ERT as the Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed ERT's obligations under the Conveyance with respect to this property.

        Effective January 1, 2000, PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon Energy Production Company L.P. ("Devon"). As a result of such merger, Devon replaced PennzEnergy as the Working Interest Owner of Eugene Island 348 and Eugene Island 208 properties effective January 1, 2000, and also assumed PennzEnergy's obligations under the Conveyance with respect to these properties. The abandonment obligations for Eugene Island 348 have been assumed by Maritech Resources, Inc. effective January 1, 2005.

        On October 9, 2001, a wholly owned subsidiary of Chevron Corporation merged (the "Merger") with and into Texaco Inc. ("Texaco"), pursuant to an Agreement and Plan of Merger, dated as of October 15, 2000. As a result of the Merger, Texaco became a wholly owned subsidiary of Chevron Corporation, and Chevron Corporation changed its name to "ChevronTexaco Corporation" in connection with the Merger. Effective May 9, 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. Accordingly, the properties referred to herein as controlled by Chevron and Texaco are each now controlled by subsidiaries of Chevron Corporation.

        On May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371 to Chevron. Chevron sold its interest in East Cameron 371 to ERT effective July 1, 2007. On July 18, 2008, Chevron sold its interest in West Cameron 643 to Hilcorp Energy GOM, LLC ("Hilcorp"). Effective August 1, 2008, Hilcorp assumed operations, reporting and payment responsibilities for West Cameron 643.

        On June 6, 2003, Anadarko Petroleum Corporation ("Anadarko") acquired, among other interests, a 25% Working Interest in the East Cameron 354 field subject to the Royalty from Amerada effective April 1, 2003. As a result of such transaction, Anadarko replaced Amerada as the Working Interest Owner of East Cameron 354 effective July 1, 2003 and also assumed Amerada's obligations under the Conveyance with respect to this property.

        Effective October 1, 2004, Apache Corporation ("Apache") acquired Anadarko's interest in East Cameron 354 and assumed Anadarko's obligations under the Conveyance with respect to this property.

        All of the Royalty Properties continue to be subject to the Royalty, though only those Royalty Properties owned by Chevron were still producing as of December 31, 2011. Chevron, as the Managing General Partner of the Partnership, calculates the Net Proceeds (as defined below) from the Royalty Properties owned by Chevron and collects financial information relating to the other Royalty Properties from the Working Interest Owners other than Chevron for presentation to the Trust.

        Unless the context in which such terms are used indicates otherwise, the terms "Working Interest Owner" and "Working Interest Owners" generally refer to the owner or owners of the Royalty Properties (Exploration I through October 31, 1986; Tenneco for periods from October 31, 1986 until November 18, 1988; Chevron with respect to all Royalty Properties for periods from November 18, 1988 until October 30, 1992, and with respect to all Royalty Properties except East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until December 1, 1994, and with respect to the same properties except West Cameron 643 thereafter; PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene/Devon Island 208 for periods from October 30, 1992 until October 1, 1995, and with respect to

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Eugene Island 348 and Eugene Devon Island 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron 371 for periods beginning on or after December 1, 1994 until May 1, 2002; SONAT with respect to East Cameron 354 for periods on or after October 1, 1995; Amoco with respect to Eugene Island 367 for periods beginning on or after October 1, 1995; Amerada with respect to East Cameron 354 for periods beginning on or after January 1, 1998 until July 1, 2003; Chevron with respect to West Cameron 643 on and after May 1, 2002 until August 1, 2008; Chevron with respect to East Cameron 371 on and after May 1, 2002 until July 1, 2007; Anadarko with respect to East Cameron 354 on and after July 1, 2003 until October 1, 2004, Apache with respect to East Cameron 354 after October 1, 2004; ERT with respect to East Cameron 371 on and after July 1, 2007; and Hilcorp with respect to West Cameron 643 on and after August 1, 2008).

        As of March 30, 2012, a total of 4,751,510 units of beneficial interest in the Trust, which we refer to herein as "Units", were issued and outstanding. The Units traded on the Nasdaq Capital Market, or "NASDAQ", from August 31, 2001 through January 2, 2011. Previously the Units were traded on the OTC Bulletin Board and on the pink sheets. On January 3, 2011, the Units were suspended from trading by the NASDAQ and the Trust filed a Form 25 with the SEC to announce the voluntary delisting of the Units. In an effort to reduce expenses, the Trustees determined that it was in the best interest of the Trust to voluntarily delist the Units and to cause the Units to no longer be traded on the NASDAQ. Since January 3, 2011, the Units have been quoted on the OTCQB™ Marketplace, which is an electronic quotation service operated by Pink OTC Markets Inc. for securities traded over-the-counter. From inception of the Trust to December 31, 2011, distributions to Unit holders totaled approximately $138,742,000 or approximately $29.20 per Unit; however, the Trust has not made a distribution to Unit holders since January 9, 2009. See "Trustee's Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources" in Item 7 of this Form 10-K and Note 4 to the Notes to Financial Statements under Item 8 of this Form 10-K for a discussion regarding uncertainties of the Trust's future distributions.

        The terms of the TEL Offshore Trust Agreement, which we refer to herein as the "Trust Agreement", provide, among other things, that: (1) the Trust is a passive entity whose activities are generally limited to the receipt of revenues attributable to the Trust's interest in the Partnership and the distribution of such revenues, after payment of or provision for Trust expenses and liabilities, to the owners of the Units; (2) the Trustees may sell all or any part of the Trust's interest in the Partnership or cause the sale of all or any part of the Royalty by the Partnership with the approval of a majority of the Unit holders or if necessary to provide for the payment of liabilities of the Trust; (3) the Trustees can establish cash reserves and can borrow funds to pay liabilities of the Trust and can pledge the assets of the Trust to secure payment of such borrowings; (4) to the extent cash available for distribution exceeds liabilities or reserves therefore established by the Trust, the Trustees will cause the Trust to make quarterly cash distributions to the Unit holders in January, April, July and October of each year; and (5) 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 million or (ii) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at approximately $11.5 million as of October 31, 2011 based on the reserve study of DeGolyer and MacNaughton, independent petroleum engineers. (See "Termination of the Trust" and Note 9 of the Notes to Financial Statements under Item 8 of this Form 10-K for further information regarding estimated future net revenues.) Upon termination of the Trust, the Trustees will sell for cash all 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 terms of the Agreement of General Partnership of the Partnership, which we refer to herein as the "Partnership Agreement," provide that the Partnership will dissolve upon the occurrence of any

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of the following: (1) December 31, 2030, (2) the election of the Trust to dissolve the Partnership, (3) the termination of the Trust, (4) the bankruptcy of the Managing General Partner of the Partnership, or (5) the dissolution of the Managing General Partner or its election to dissolve the Partnership; however, the Managing General Partner has agreed not to dissolve or to elect to dissolve the Partnership and will be liable for all damages and costs to the Trust if it breaches such agreement.

        Under the Conveyance and the Partnership Agreement, the Trust is entitled to its share (99.99%) of the Partnership's 80% interest in 25% of the Net Proceeds, as hereinafter defined, realized from the sale of the oil, gas and associated hydrocarbons when produced from the Royalty Properties. See "Description of Royalty Properties." The Conveyance provides that the Working Interest Owners will calculate, for each quarterly period 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. "Net Proceeds" means for each quarterly period, the excess, if any, of the Gross Proceeds, as hereinafter defined, for such period over Production Costs, as hereinafter defined, for such period. "Gross Proceeds" means the amounts received by the Working Interest Owners from the sale of oil, gas and associated hydrocarbons produced from the properties burdened by the Royalty, subject to certain adjustments. Gross 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. "Production Costs" means, generally, costs incurred on an accrual basis by the Working Interest Owners in operating the Royalty Properties, including capital and non-capital costs. In general, Net Proceeds are computed on an aggregate basis and consist of the aggregate proceeds to the Working Interest Owners from the sale of oil and gas from the Royalty Properties less (1) all direct costs, charges and expenses incurred by the Working Interest Owners in exploration, production, development, drilling and other operations on the Royalty Properties (including secondary recovery operations); (2) all applicable taxes (including severance and ad valorem taxes) excluding income taxes; (3) all operating charges directly associated with the Royalty Properties; (4) an allowance for costs, computed on a current basis at a rate equal to the prime rate of JPMorgan Chase Bank plus 0.5% on all amounts by which, and for only so long as, costs and expenses for the Royalty Properties incurred for any quarter have exceeded the proceeds of production from such Royalty Properties for such quarter; (5) applicable charges for certain overhead expenses as provided in the Conveyance; (6) the management fees and expense reimbursements owing the Working Interest Owners; and (7) a special cost reserve for the future costs to be incurred by the Working Interest Owners to plug and abandon wells and dismantle and remove platforms, pipelines and other production facilities from the Royalty Properties and for future drilling projects and other estimated future capital expenditures on the Royalty Properties. The Trustees are not obligated to return any Royalty income received in any period, but future amounts otherwise payable will be reduced by the amount of any prior overpayments of such Royalty income. The Working Interest Owners are required to maintain books and records sufficient to determine amounts payable under the Royalty. The Working Interest Owners are also required to deliver to the Managing General Partner on behalf of the Partnership a statement of the computation of Net Proceeds no later than the tenth business day prior to the quarterly record date.

        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 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.

        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

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Royalty were estimated at approximately $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. 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 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 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% is 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.

        Despite the sale of the 20% interest in the Royalty in 2011, absent the receipt of Net Proceeds or other actions being taken, it is anticipated that during the first quarter of 2013, the Trust will not have sufficient funds to pay the liabilities of the Trust. As such, the Trustee may be required to take further actions, on behalf of the Trust as permitted under the Trust Agreement, that could materially impact the Unit holders. Such actions include the potential borrowing of funds, which may be secured by the Trust's assets, or the sale of all or a part of the Trust's interests in the Partnership or causing the Partnership to sell all or a part of the Trust's remaining interest in the Royalty.

        The Royalty Properties are required to be operated in accordance with standards applicable to a prudent oil and gas operator. The Working Interest Owners are free to transfer their working interest in any of the Royalty Properties (burdened by the Royalty) to third parties. The Working Interest Owners are also free to enter into farm-out agreements whereby a Working Interest Owner would transfer a portion of its interest (unburdened by the Royalty) while retaining a lesser interest (burdened by the Royalty) in return for the transferee's obligation to drill a well on the Royalty Properties. The

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Working Interest Owners have the right to abandon any well or lease, and upon termination of any lease, the part of the Royalty relating thereto will be extinguished. The Working Interest Owners are primarily the operators of the respective Royalty Properties although certain other parties are, and have also been, operators for the Royalty Properties.

        The discussions of terms of the Trust Agreement, Partnership Agreement and Conveyance contained herein are qualified in their entirety by reference to the Trust Agreement, Partnership Agreement and Conveyance themselves, which are exhibits to this Form 10-K and are available upon request from the Corporate Trustee.

        The Trust has no employees. Administrative functions of the Trust are performed by the Corporate Trustee.

History of the Trust

        Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the Trust effective January 1, 1983, pursuant to a Plan of Dissolution ("Plan"), which was approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the assets of Tenneco Offshore were transferred to the Trust as of January 1, 1983, and Units were exchanged for shares of common stock of Tenneco Offshore on the basis of one Unit for each share of common stock held by stockholders of record on January 14, 1983. Additionally, the Partnership was formed, in which the Trust owned a 99.99% interest and Tenneco initially owned a .01% interest. The Partnership was formed solely for the purpose of owning the Royalty, receiving the proceeds from the Royalty, paying the liabilities and expenses of the Partnership and disbursing remaining revenues to the Trust and the Managing General Partner of the Partnership in accordance with their interests. The Plan was effected by transferring an overriding royalty interest equivalent to a 25% net profits interest in the oil and gas properties of Exploration I located offshore Louisiana to the Partnership, contributing the common stock of Tenneco Offshore II Company to the Trust, and issuing certificates evidencing Units in liquidation and cancellation of Tenneco Offshore's common stock.

        On October 31, 1986, Exploration I was dissolved and the oil and gas properties of Exploration I were distributed to Tenneco subject to the Royalty. Tenneco, who was then serving as the Managing General Partner of the Partnership, assumed the obligations of Exploration I, including its obligations under the Conveyance. The dissolution of Exploration I had no impact on future cash distributions to holders of units of beneficial interest.

        As discussed above, on November 18, 1988, Chevron replaced Tenneco as the Working Interest Owner and Managing General Partner of the Partnership and assumed Tenneco's obligations under the Conveyance. On October 30, 1992, PennzEnergy acquired certain oil and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by PennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of such acquisition, PennzEnergy replaced Chevron as the Working Interest Owner of such properties and assumed Chevron's obligations under the Conveyance with respect to such properties on October 30, 1992. On December 1, 1994, TEPI acquired two of the Royalty Properties from Chevron. The Royalty Properties acquired by TEPI were West Cameron 643 and East Cameron 371. As a result of such acquisition, TEPI replaced Chevron as the Working Interest Owner of such properties and assumed Chevron's obligations under the Conveyance with respect to such properties on December 1, 1994. On October 1, 1995, SONAT and Amoco acquired the East Cameron 354 and Eugene Island 367 properties, respectively, from PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced PennzEnergy as the Working Interest Owners of the East Cameron 354 and Eugene Island 367 properties, respectively, and also assumed PennzEnergy's obligations under the Conveyance with respect to such properties on October 1, 1995. Effective January 1, 1998 ERT acquired the East Cameron 354 property from SONAT. As a result of such acquisition, ERT replaced SONAT as the

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Working Interest Owner of the East Cameron 354 property and also assumed SONAT's obligations under the Conveyance with respect to this property effective January 1, 1998. In October 1998, Amerada acquired the East Cameron 354 property from ERT effective January 1, 1998. As a result of this acquisition, Amerada replaced ERT as the Working Interest Owner of the East Cameron 354 property effective January 1, 1998, and also assumed ERT's obligations under the Conveyance with respect to this property. Effective January 1, 2000, PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon. As a result of such merger, Devon replaced PennzEnergy as the Working Interest Owner of the Eugene Island 348 and Eugene Island 208 properties effective January 1, 2000, and also assumed PennzEnergy's obligations under the Conveyance with respect to these properties. On October 9, 2001, a wholly owned subsidiary of Chevron Corporation merged with and into Texaco, pursuant to an Agreement and Plan of Merger, dated as of October 15, 2000. As a result of the Merger, Texaco Inc. became a wholly owned subsidiary of Chevron Corporation, and Chevron Corporation changed its name to "ChevronTexaco Corporation" in connection with the Merger. Accordingly, the properties referred to herein as controlled by Chevron and Texaco are each now controlled by subsidiaries of Chevron Corporation. Effective May 9, 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. On May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371 to Chevron. Chevron sold its interest in East Cameron 371 to ERT effective July 1, 2007. Chevron sold its interests in West Cameron 643 to Hilcorp effective August 1, 2008. On June 6, 2003, Anadarko acquired, among other interests, a 25% Working Interest in the East Cameron 354 field, subject to the Royalty, from Amerada effective April 1, 2003. As a result of this transaction, Anadarko replaced Amerada as the Working Interest Owner of East Cameron 354 effective July 1, 2003 and also assumed Amerada's obligations under the Conveyance with respect to this property. Effective October 1, 2004, Apache acquired Anadarko's interest in East Cameron 354 and assumed Anadarko's obligations under the Conveyance with respect to this property.

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DESCRIPTION OF THE UNITS

        Each Unit is evidenced by a transferable certificate issued by the Corporate Trustee. Each unit ranks equally as to distributions, has one vote on any matter submitted to Unit holders and represents an undivided interest in the Trust, which in turn owns a 99.99% interest in the Partnership.

Distributions

        The Trustees distribute the Trust's income pro rata for each calendar quarter within 10 days after the end of each calendar quarter. Distributions of the Trust's income are made to Unit holders of record on the Quarterly Record Date, which is the last business day of each quarterly period, or such later date as the Trustees determine is required to comply with legal requirements. The Trustees determine for each quarterly period the amount available for distribution. Such amount (the "Quarterly Income Amount") consists of the cash received from the Royalty during the quarterly period plus any other cash receipts of the Trust, less the obligations of the Trust paid during the quarterly period, and adjusted for changes made by the Trust during the quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. 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 reserve amount at December 31, 2011 and 2010 was $944,917 and $352,017, respectively. The Trust has not received a distribution from the Partnership for Net Proceeds since December 2008; thus, the Trust has not made a distribution to Unit holders since January 9, 2009. The Trust did receive a distribution of approximately $1,485,851 in October 2011 with respect to the Partnership's sale of 20% of the Royalty, and the Trust will use such money solely for the payment of expenses of the Trust. As described herein, 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. Because of the lack of receipt of Net Proceeds, the Trust has previously not had sufficient cash flow to pay expenses on a current basis; while the Trust has realized proceeds of approximately $1,485,851 from the sale by the Partnership of 20% of the Royalty, absent the receipt of Net Proceeds or other actions being taken, the Trust may in the future still not have sufficient cash flow to pay expenses on a current basis. See "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" in Item 7 of this Form 10-K.

        Within 90 days of the close of each year, the net federal taxable income of the Trust for each quarterly period ending in such year is reported by the Trustees for federal tax purposes to the Unit holder of record to whom the Quarterly Income Amount was distributed.

Possible Requirement That Units Be Divested

        The Trust Agreement imposes no restrictions based on nationality or other status of the persons or other entities who are eligible to hold Units. However, the Trust Agreement provides that if at any time the Trust or any of the Trustees are named as a party in any judicial or administrative or other governmental proceeding that seeks the cancellation or forfeiture of any interest in any property located in the United States in which the Trust has an interest because of the nationality or any other status of any one or more owners of Units, or if at any time the Trustees in their reasonable discretion determine that such a proceeding is threatened or likely to be asserted and the Trust has received an

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opinion of counsel stating that the party asserting or likely to assert the claims has a reasonable probability of succeeding in such claim, the following procedures will be applicable:

        (a)   The Trustees, in their discretion, may seek from an investment banking firm to be selected by the Trustees an opinion as to whether it is in the Trust's best interest for the Trustees to take the actions permitted by (b)(i) through (iii) below.

        (b)   The Trustees may take no action with respect to the potential cancellation or forfeiture or may seek to avoid such cancellation or forfeiture by the following procedure:

          (i)  The Trustees will promptly give written notice ("Notice") to each record owner of Units as to the existence of or probable assertion of such controversy. The Notice will contain a reasonable summary of such controversy, will include materials which will permit an owner of Units to promptly confirm or deny to the Trustees that such owner is a person whose nationality or other status is or would be an issue in such a proceeding ("Ineligible Holder") and will constitute a demand to each Ineligible Holder that he dispose of his Units, to a party who would not be an Ineligible Holder, within 30 days after the date of the Notice.

         (ii)  If an Ineligible Holder fails to dispose of his Units as required by the Notice, the Trustees will have the right to redeem and will redeem, during the 90 days following the termination of the 30-day period specified in the Notice, any Unit not so transferred for a cash price equal to the mean between the closing bid and ask prices of the Units in the over-the-counter market or, if the Units are then listed on a stock exchange, the closing price of the Units on the largest stock exchange on which the Units are listed, on the last business day prior to the expiration of the 30-day period stated in the Notice. The procedures for any such purchase are more fully described in the Trust Agreement. The Trustees will cancel any Units acquired in accordance with the foregoing procedures thereby increasing the proportionate interest in the Trust of other holders of Units.

        (iii)  The Trustees may, in their sole discretion, cause the Trust to borrow any amounts required to purchase Units in accordance with the procedures described above.

Liability of Unit Holders

        It is the intention of the Working Interest Owners and the Trustees that the Trust be an "express trust" under the Texas Trust Act. Under Texas law, beneficiaries of an express trust are not personally liable for the obligations of the trust, even if the assets of the trust are insufficient to discharge its obligations. However, it is unclear under Texas law whether the Trust will be held to constitute an express trust and, if it is not held to be an express trust, whether the holders of Units would be jointly and severally liable for the obligations of the Trust as would general partners of a partnership.

        With respect to sales certificates issued by the Federal Energy Regulatory Commission, which we refer to herein as the "FERC", although the FERC has the power to compel refunds, it has not compelled refunds from overriding royalty interest owners with respect to gas price overcharges. However, future laws, regulations or judicial decisions might permit the FERC or other governmental agencies to require such refunds from overriding royalty interest owners or create filing, reporting or certification obligations with respect to a trust created for such overriding royalty interest owners. Moreover, other parties, such as oil or gas purchasers, may be able to instigate private lawsuits or other legal action to compel refunds from overriding royalty interest owners with respect to oil or gas pricing overcharges.

        The Working Interest Owners have agreed that they will not seek to recover from the Unit holders the amount of any refunds they are required to make, except out of future revenues payable to the Trust. The Trustees will be liable to the Unit holders if the Trustees allow any liability to be incurred without taking any and all action necessary to ensure that such liability will be satisfiable only out of

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the Trust assets (regardless of whether the assets are adequate to satisfy the liability) and will be non-recourse to the Unit holders. However, the Trustees will not be liable to the Unit holders for state or federal income taxes or for refunds, fines, penalties or interest relating to oil or gas pricing overcharges under state or federal price controls. The Trustees will be indemnified from the Trust assets, to the extent that the Trustees' actions do not constitute gross negligence, bad faith or fraud.

        Each Unit holder should consider, in weighing the possible exposure to liability in the event the Trust were not classified as an express trust, (1) the substantial value and passive nature of the Trust assets, (2) the restrictions on the power of the Trustees to incur liabilities on behalf of the Trust and (3) the limited activities to be conducted by the Trustees.

Federal Income Tax Matters

        This section is a summary of federal income tax matters of general application which addresses the material tax consequences of the ownership and sale of the Units. Except where indicated, the discussion below describes general federal income tax considerations applicable to individuals who are citizens or residents of the United States. Accordingly, the following discussion has limited application to domestic corporations and persons subject to specialized federal income tax treatment, such as regulated investment companies and insurance companies. It is impractical to comment on all aspects of federal, state, local and foreign laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in the Units as they relate to the particular circumstances of every Unit holder. Each Unit holder is encouraged to consult his own tax advisor with respect to his particular circumstances.

        This summary is based on current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), existing and proposed Treasury Regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the Internal Revenue Service ("IRS"). No assurance can be provided that the statements set forth herein (which do not bind the IRS or the courts) will not be challenged by the IRS or will be sustained by a court if so challenged.

Classification of the Trust

        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.

        The Trustees assume that some Units are held by a middleman as such term is broadly defined in applicable Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name).

        Therefore, the Trustees consider the Trust to be a non-mortgage widely held fixed investment trust ("WHFIT") for federal income tax purposes. The Corporate Trustee, 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, is the representative of the Trust that will provide tax information in accordance with applicable Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Units on behalf of Unit holders, and not the Trustees of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury Regulations with respect to such Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unit holders whose Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Units.

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Income and Depletion

        Each Unit holder of record as of the last business day of each quarter will be allocated a share of the income and deductions of the Trust, including the Trust's share of the income and deductions of the Partnership, computed on an accrual basis, for that quarter. Royalty income is portfolio income. Since all income from the Partnership is Royalty income, this amount, net of depletion and severance taxes, is portfolio income and, subject to certain exceptions and transitional rules, this Royalty income cannot be offset by passive losses. Additionally, interest income is portfolio income. Administrative expense is an investment expense.

        The IRS has also ruled that the Royalty is a non-operating economic interest giving rise to income subject to depletion. The Trustees will treat the Royalty as a single property giving rise to income subject to depletion, although the computation of depletion will be made by each Unit holder based upon information provided by the Trustees. Each Unit holder will be entitled to compute cost depletion with respect to his share of income from the Royalty based on his basis in the Royalty. A Unit holder will have a basis in the Royalty equal to the basis in his Units less any amount allocable to his share of any cash reserve account. Transferees of Units transferred after October 11, 1990, may be eligible to use the percentage depletion deduction on oil and gas income thereafter attributable to such Units, if the percentage depletion deduction would exceed cost depletion. Unlike cost depletion, percentage depletion is not limited to a Unit holder's depletable tax basis in the Units. Rather, a Unit holder may be entitled to a percentage depletion deduction as long as the Royalty generates gross income.

Backup Withholding

        Distributions from the Trust are generally subject to backup withholding, currently at a rate of 28% (but scheduled to increase to 31% for taxable years beginning on or after January 1, 2013, absent new legislation). Backup withholding generally will not apply to distributions to a Unit holder unless the Unit holder fails to properly provide to the Trust his taxpayer identification number or the IRS notifies the Trust that the taxpayer identification number provided by the Unit holder is incorrect.

Sale of Units

        Generally, except for recapture items, the sale, exchange or other disposition of a Unit will result in capital gain or loss measured by the difference between the tax basis in the Unit and the amount realized. Effective for property placed in service after December 31, 1986, the amount of gain, if any, realized upon the disposition of oil and gas property is treated as ordinary income to the extent of the intangible drilling and development costs incurred with respect to the property and depletion claimed with respect to the property to the extent it reduced the taxpayer's basis in the property. Under this provision, depletion attributable to a Unit acquired after 1986 will be subject to recapture as ordinary income upon disposition of the Unit or upon disposition of the oil and gas property to which the depletion is attributable. The balance of any gain or any loss will be capital gain or loss if the Unit was held by the Unit holder as a capital asset, either long-term or short-term depending on the holding period of the Unit. This capital gain or loss will be long-term if a Unit holder's holding period for the Unit exceeds one year at the time of sale or exchange. Capital gain or loss will be short-term if the Unit has not been held for more than one year at the time of sale or exchange. Under current law, the highest marginal U.S. federal income tax rate applicable to long-term capital gains of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to long-term capital gains of individuals will increase to 20%. Moreover, this rate is subject to change by new legislation at any time. The deductibility of capital losses are subject to certain limitations.

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Non-U.S. Unit holders

        In general, a Unit holder who is a nonresident alien individual or which is a foreign corporation, each a "non-U.S. Unit holder" for purposes of this discussion, will be subject to tax on the gross income (without taking into account any deductions, such as depletion) produced by the Royalty at a rate equal to 30%, or if applicable, at a lower treaty rate. This tax will be withheld by the Trustees and remitted directly to the United States Treasury. A non-U.S. Unit holder may elect to treat the income from the Royalty as effectively connected with the conduct of a United States trade or business under provisions of the Code, or pursuant to any similar provisions of applicable treaties. Upon making this election a non-U.S. Unit holder is entitled to claim all deductions with respect to that income, but he must file a United States federal income tax return to claim those deductions. This election once made is irrevocable, unless an applicable treaty allows the election to be made annually. However, that effectively connected taxable income is subject to withholding at the highest applicable tax rate, currently 35% for individual non-U.S. Unit holders.

        The Code and the Treasury Regulations thereunder treat the Trust as if it were a United States real property holding corporation. Accordingly, a non-U.S. Unit holder may be subject to United States federal income tax on any gain from the disposition of his Units if he meets certain ownership thresholds.

        In addition, if a foreign corporation elects under provisions of the Code to treat the income from the Royalty as effectively connected with the conduct of a United States trade or business, the corporation may also be subject to the U.S. branch profits tax at a rate of 30%. This tax is imposed on U.S. branch profits of a foreign corporation that are not reinvested in the U.S. trade or business. This tax is in addition to the tax on effectively connected income. The branch profits tax may be either reduced or eliminated by treaty.

        Federal income taxation of a non-U.S. Unit holder is a highly complex matter which may be affected by many other considerations. Therefore, each non-U.S. Unit holder is encouraged to consult its own tax advisor with respect to its ownership of Units.

Tax-exempt Organizations

        Investments in publicly traded grantor trusts are treated the same as investments in partnerships for purposes of the rules governing unrelated business taxable income. Royalty income and interest income should not be unrelated business taxable income so long as, generally, a Unit holder did not incur debt to acquire a Unit or otherwise incur or maintain a debt that would not have been incurred or maintained if that Unit had not been acquired. Legislative proposals have been made from time to time which, if adopted, would result in the treatment of Royalty income as unrelated business taxable income. Each tax-exempt Unit holder is encouraged to consult its own tax advisor with respect to its ownership of Units and the treatment of Royalty income.

State Law Considerations

        The Trust and the Partnership have been structured so as to cause the Units to be treated for certain state law purposes essentially the same as other securities, that is, as interests in intangible personal property rather than as interests in real property. However, in the absence of controlling legal precedent, there is a possibility that under certain circumstances a Unit holder could be treated as owning an interest in real property under the laws of Louisiana. In that event, the tax, probate, devolution of title and administration laws of Louisiana or other states applicable to real property may apply to the Units, even if held by a person who is not a resident thereof. Application of these laws could make the inheritance and related matters with respect to the Units substantially more onerous than had the Units been treated as interests in intangible personal property. Unit holders are

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encouraged to consult their legal and tax advisors regarding the applicability of these considerations to their individual circumstances.

        Texas does not impose an income tax. Therefore, no part of the income produced by the Trust is subject to an income tax in Texas. However, Texas imposes a tax at a rate of 1% on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax statute. Entities subject to tax generally include trusts unless otherwise exempt, and most other types of entities having limited liability protection. Trusts and partnerships that receive at least 90% of their federal gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are generally exempt from the Texas franchise tax as "passive entities." The Trust should be exempt from Texas franchise tax as a "passive entity." Since the Trust should be exempt from Texas franchise tax at the Trust level as a passive entity, each Unit holder that is considered a taxable entity under the Texas franchise tax would generally be required to include its Texas portion of Trust revenues in its own Texas franchise tax computation. Each Unit holder is urged to consult its own tax advisor regarding its possible Texas franchise tax liability.

TERMINATION OF THE TRUST

        The terms of the TEL Offshore Trust Agreement provide that the Trust will terminate upon the first to occur of the following events: (1) 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 million or (2) a decision to terminate the Trust by the affirmative vote of Unit holders representing a majority of the Units. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at $11.5 million as of October 31, 2011, based on the reserve study of DeGolyer and MacNaughton, independent petroleum engineers, discussed herein. Such reserve study does not include any reserves or volumes attributable to Eugene Island 339; however, it does include the then-estimated costs of approximately $17.6 million for estimated plugging and abandonment costs related to Eugene Island 339 attributable to the Royalty, 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. The $17.6 million of estimated plugging and abandonment costs included in the reserve study is less than the $18.7 million of plugging and abandonment costs estimated by Chevron in March 2012. Based on the DeGolyer and MacNaughton reserve study, as of October 31, 2011, it is estimated that approximately 67% of future net revenues from the Royalty Properties are expected to be generated during the next three years. 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 the limitations described in the summary of the DeGolyer and MacNaughton reserve study included in Item 1 of this Form 10-K. The reserve study is limited to reserves classified as proved; therefore, future capital expenditures for recovery of reserves not classified as proved by DeGolyer and MacNaughton are not included in the calculation of estimated future net revenues, nor are any capital expenditures included for any redevelopment of Eugene Island 339. In addition, 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

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in its entirety by reference to the Trust Agreement itself, which is an exhibit to this Form 10-K and is available upon request from the Corporate Trustee.

        In addition, in the event of a dissolution of the Partnership (which could occur under the circumstances described above under "Description of the Trust") and a subsequent winding up and termination thereof, the assets of the Partnership (i.e., the Partnership's interest in the Royalty) could either (1) be distributed in kind ratably to the Trust and the Managing General Partner or (2) be sold and the proceeds thereof distributed ratably to the Trust and the Managing General Partner. In the event of a sale of the Partnership's interest in the Royalty and a distribution of the cash proceeds thereof to the Trust and the Managing General Partner, the Trustees would make a final distribution to Unit holders of the Trust's portion of such cash proceeds plus any other cash held by the Trust after payment of or provision for all liabilities of the Trust, and the Trust would be terminated.

Royalty Income, Distributable Income and Total Assets

        Reference is made to Items 6, 7 and 8 of this Form 10-K for financial information relating to the Trust.

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Description of Royalty Properties

Properties and Wells

        The Partnership's interest consists of an 80% interest in an overriding royalty interest, with the entire overriding royalty interest equivalent to a 25% net profits interest, in the Royalty Properties as follows:

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        The following is a summary of the number of developmental and exploratory wells drilled on the Royalty Properties during the last three years:

Reserves

        A study of the proved oil and gas reserves attributable to the Partnership, in which the Trust has a 99.99% interest, has been made by DeGolyer and MacNaughton, independent petroleum engineering consultants, as of October 31, 2011. A copy of the reserve study has been filed as an exhibit to this Form 10-K. The following is a summary of such reserve study. Such study reflects estimated production, reserve quantities and future net revenue based upon estimates of the future timing of actual production without regard to when received by the Trust, which differs from the manner in which the

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Trust recognizes its Royalty income. See Notes 2 and 9 in the Notes to Financial Statements under Item 8 of this Form 10-K.

        On the last business day of each calendar quarter, the Working Interest Owners pay to the Partnership 20% of the Net Proceeds (which represents the Partnership's 80% interest in 25% of the Net Proceeds) for the immediately preceding Quarterly Period; prior to the sale by the Partnership of 20% of the Royalty, which was effective August 1, 2011, the Working Interest Owners would pay to the Partnership 25% of the Net Proceeds from the then 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. Any cash conveyed to the Trust from the Royalty during the quarter ended December 31, 2011 would substantially represent the revenues and expenses from the Royalty Properties from August through October 2011. The financial and operating information included in this Form 10-K for the 12 months ended December 31, 2011 primarily represents financial and operating information with respect to the Royalty Properties for the months of November 2010 through October 2011. Thus, DeGolyer and MacNaughton's reserve study was made as of October 31, 2011. The reserve study bases proved developed reserves on oil and gas prices based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended October 31, 2011. Proved reserve estimates do not include any value for probable or possible reserves that may exist, categories that SEC rules permit the Trust to disclose in its public reports.

        During September 2008, the platforms and wells associated with the Eugene Island 339 field were completely destroyed by Hurricane Ike. Chevron is proceeding with the work required to clear the remaining infrastructure and abandon existing wells. None of the reserve studies prepared as of October 31, 2009, October 31, 2010 or October 31, 2011 includes reserves attributable to Eugene Island 339 or any capital expenditures for any redevelopment of Eugene Island 339. However, each such reserve study does include the estimated total plugging and abandonment costs related to Eugene Island 339, with costs to the Royalty relating thereto estimated to be approximately $17.6 million for purposes of the October 31, 2011 reserve report of which approximately $16.5 million had been incurred. The $17.6 million of estimated plugging and abandonment costs included in the reserve study is less than the $18.7 million of plugging and abandonment costs estimated by Chevron in March 2012. Approximately $18.1 million of such plugging and abandonment costs had been incurred through January 31, 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.

        The 2011 reserve study notes that there were four productive Royalty Properties, which consist of Ship Shoal 182/183, South Timbalier 36 and South Timbalier 37 and West Cameron Block 643. For a discussion of Royalty Properties, see "Trustee's Discussion and Analysis of Financial Condition and Results of Operation—Operations."

        There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data in the DeGolyer and MacNaughton study represent estimates only and should not be construed as being exact. The discounted present values shown by the DeGolyer and MacNaughton study should not be construed as the current market value of the estimated gas and oil reserves attributable to the Royalty Properties or the costs that would be incurred to obtain equivalent reserves, since a market value determination would include many additional factors. Estimates were prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board. Accordingly, the estimates are based on existing economic

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and operating conditions in effect at October 31, 2011, with no provision for future increases or decreases except for periodic price redeterminations in accordance with existing gas contracts. Actual future prices and costs may be materially greater or less than the assumed amounts in the reserve study. Because the reserve study is limited to proved reserves, future capital expenditures for recovery of reserves not classified as proved by DeGolyer and MacNaughton are not included in the calculation of estimated future net revenues. Reserve assessment is a subjective process of estimating the recovery from underground accumulations of gas and oil that cannot be measured in an exact way, and estimates of other persons might differ materially from those of DeGolyer and MacNaughton. Accordingly, reserve estimates are often different from the quantities of hydrocarbons that are ultimately recovered.

        Estimated net proved reserves attributable to the interest in the net profits interest owned by the Partnership, for each of the three years in the period ended October 31, 2011, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):

        Information used in the preparation of the reserve study was obtained from Working Interest Owners. All of the reserve estimates are classified as proved developed reserves. There are no proved undeveloped reserves for the Royalty Properties subject to the report.

        The Partnership's share of gas sales are recorded by the Working Interest Owners on the cash method of accounting or based on actual production. When revenues are reported on actual production, there is no gas imbalance created. Under the cash method, revenues are recorded based on actual gas volumes sold, which could be more or less than the volumes the Working Interest Owners are entitled to based on their ownership interests. The Partnership's Royalty income for a period reflects the actual gas sold during the period.

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        While estimates of reserves attributable to the Royalty are shown in order to comply with requirements of the SEC, there is no precise method of allocating estimates of physical quantities of reserves to the Partnership and the Trust, since the Royalty is not a working interest and the Partnership does not own and is not entitled to receive any specific volume of reserves from the Royalty. Reserve quantities in the DeGolyer and MacNaughton reserve study have been allocated based on a revenue formula and such quantities can be affected by future changes in various economic factors utilized in estimating future gross and net revenues from the Royalty Properties. Therefore, the estimates of reserves set forth in the DeGolyer and MacNaughton study are to a large extent hypothetical and differ in significant respects from estimates of reserves attributable to a working interest. For a further discussion of reserves, reference is made to Note 9 in the Notes to Financial Statements under Item 8 of this Form 10-K.

        The future net revenues contained in the DeGolyer and MacNaughton reserve study do not take into account the approximately $5.9 million, net to the entire Royalty, as of October 31, 2011, by which aggregate Production Costs for the Royalty Properties have exceeded the related Gross Proceeds for the Royalty Properties since November 2008, or any required deposits to the Special Cost Escrow account. The future net revenues contained in the DeGolyer and MacNaughton reserve study have not been reduced for future costs and expenses of the Trust, which are expected to approximate $800,000 annually. The costs and expenses of the Trust may increase in future years, depending on increases in accounting, engineering, legal and other professional fees, as well as other factors. Increased legal fees may occur in connection with, among other things, any borrowing or sales effected by the Trust or the Partnership in order to provide liquidity to the Trust.

        Total future net revenues attributable to the Partnership's interest in the Royalty were estimated in the reserve study at $11.5 million as of October 31, 2011. The present value of the total future net revenues attributable to the Partnership's interest in the Royalty, discounted at 10 percent, were estimated in the reserve study at $8.53 million as of October 31, 2011. Revenue values in the reserve study were estimated using the initial costs provided by Chevron and unweighted average prices of $92.34 per barrel of oil and $4.32 per Mcf of natural gas. The future net revenue value was calculated by deducting operating expenses and capital costs from future gross revenue of the combined interests of the Partnership and the Working Interest Owners in the Royalty Properties. Current estimates of operating expenses were used for the life of the properties with no increases in the future based on inflation. The values were reduced by a trust overhead charge furnished by Chevron. Capital and abandonment costs for longer-life properties were accrued at the end of each quarter in amounts specified by Chevron beginning in January 2012. The future accrual or escrow amounts for the Royalty Properties were deducted from the future net revenue at the end of each quarter, as specified by Chevron.

        Because the DeGolyer and MacNaughton reserve study is limited to proved reserves, future capital expenditures for recovery of reserves not classified as proved by DeGolyer and MacNaughton are not included in the calculation of future net revenues nor are any capital expenditures for any redevelopment of Eugene Island 339. These capital expenditures could have a significant effect on the actual future net revenues attributable to the Partnership's interest in the Royalty.

        The Trustees rely on DeGolyer and MacNaughton to prepare the reserve study of the oil and gas reserves attributable to the Partnership, in which the Trust has a 99.99% interest. The Trustees do not control the information provided by the Working Interest Owners or the assumptions made or methodologies used by the third-party reserve engineer. Accordingly, such information is outside the scope of the internal controls of the Trust and the Trustees.

        Chevron, as the Managing General Partner of the Partnership, maintains oversight and compliance responsibility for the internal reserve estimate process and, in accordance with internal policies and procedures, provides appropriate data to independent third party engineers for the annual estimation of

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year-end reserves. Chevron accumulates historical production data for the Royalty Properties, calculates historical lease operating expenses and differentials, updates working interests and net revenue interests, and obtains logs, 3-D seismic and other geological and geophysical information. This data is forwarded to DeGolyer & MacNaughton, thereby allowing DeGolyer & MacNaughton to prepare estimated proved reserves in their entirety based on such data.

        Estimates of the proved oil and gas reserves attributable to the Partnership as of October 31, 2010 and 2011 are based on reports of DeGolyer & MacNaughton. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Calgary, and Moscow. The firm's more than 80 professionals include engineers, geologists, geophysicists, petrophysicists, and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies, equity studies and studies of supply and economics related to the domestic and international energy industry. These services have been provided for over 70 years. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any oil, gas, or mineral properties. The firm subscribes to a code of professional conduct, and its employees support their related technical and professional societies.

        The technical person at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve study is a Registered Professional Engineer in the State of Texas with more than 35 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1974 and he is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists.

        The Trust Agreement provides that the Trust will terminate in the event 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. See "Business—Termination of the Trust".

        The Managing General Partner of the Partnership has advised the Trust that, as of March 30, 2012, there had been no events subsequent to October 31, 2011 that have caused a significant change in the estimated proved reserves referred to in the DeGolyer and MacNaughton study.

Operations and Production

        Reference is made to the Section entitled "—Operations" under Item 7 of this Form 10-K for information concerning operations and production.

Distributions

        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 had not made a distribution since January 9, 2009.

        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

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with such damages, including the expenditures required to plug and abandon the wells on Eugene Island 339. In addition, in October 2011, the Partnership sold 20% of the Royalty; thus, the Partnership will receive in the future only 80% of the Net Proceeds if and when there are sufficient Net Proceeds for distribution on the Royalty. While Chevron has taken steps 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 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 $18.1 million of which had been incurred through January 31, 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 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 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. Despite the participation agreement, it is anticipated that 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. See "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and also "—Operations."

MARKETING

        The amount of cash distributions to the Trust is dependent on, among other things, the sales prices for oil and gas produced from the Royalty Properties and the quantities of oil and gas sold.

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

Gas Marketing

        During the years ended December 31, 2011, 2010 and 2009, 100% of Chevron's natural gas and natural gas liquids relative to the Royalty Properties were committed and sold to Chevron Natural Gas at spot market prices. Prices for natural gas paid by Chevron Natural Gas in fiscal 2011 ranged from $3.91 to $5.64 per Mcf.

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        It should be noted that the Conveyance provides that amounts received by the producer pursuant to "take-or-pay" provisions are not included within the Royalty payable to the Partnership unless and until gas is actually delivered pursuant to the "make-up" provisions, if any, of the applicable contract. Accordingly, amounts received by the Working Interest Owners as "take-or-pay" payments are not included in the calculation of the Royalty payable, and the income received by the Partnership is restricted to amounts paid for gas actually delivered.

        Due to the seasonal nature of demand for natural gas and its effects on sales prices and production volumes, the amount of gas sold with respect to the Royalty Properties may vary. Generally, production volumes and prices are higher during the first and fourth quarters of each calendar year. Because of the time lag between the date on which the Working Interest Owners receive payment for production from the Royalty Properties and the date on which distributions are made to Unit holders, the seasonality that generally affects production volumes and prices is generally reflected in distributions to the Trust in later periods.

Oil Marketing

        Crude oil purchases by Chevron accounted for approximately 98% of total crude oil revenues from the Royalty Properties operated by Chevron during 2009, approximately 100% of the total crude oil revenues from the Royalty Properties operated by Chevron during 2010, and approximately 100% of the total crude oil revenues from the Royalty Properties operated by Chevron during 2011.

        Chevron purchases the crude oil at prices based on a market index for the applicable grade of crude oil, as adjusted for gravity and transportation charges, if applicable. Prices for crude oil paid by Chevron in fiscal 2011 ranged from $85.65 per barrel to $117.60 per barrel.

COMPETITION AND REGULATION

Competition

        The Working Interest Owners experience competition from other oil and gas companies in all phases of their operations. Numerous companies participate in the exploration for and production of oil and gas. The Working Interest Owners have previously advised the Trust that they believe that their competitive positions are affected by price and contract terms. Business is affected not only by such competition, but also by general economic developments, governmental regulations and other factors.

Regulation—General

        The production of oil and gas by the Working Interest Owners is affected by many state and federal regulations with respect to allowable rates of production, drilling permits, well spacing, marketing, environmental matters and pricing. Future regulations could change allowable rates of production or the manner in which oil and gas operations may be lawfully conducted. Sales of natural gas in interstate commerce for resale and the transportation of natural gas in interstate commerce are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938, as amended (the "Natural Gas Act").

FERC Regulation

        In general, under the Natural Gas Act, the FERC regulates the sale of natural gas in interstate commerce for resale and the transportation of natural gas in interstate commerce by interstate pipelines. The FERC has issued orders and adopted regulations resulting in a restructuring of the natural gas industry. The principal elements of this restructuring were the requirement that interstate pipelines separate, or "unbundle," into individual components the various services offered on their systems, with all transportation services to be provided on a non-discriminatory basis, and the

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prohibition against an interstate pipeline providing gas sales services except through separately-organized affiliates. In various rulemaking proceedings following its initial unbundling requirement, the FERC has refined its regulatory program applicable to interstate pipelines in various respects, and it has announced that it will continue to monitor these regulations to determine whether further changes are needed. In addition to rulemaking proceedings, the FERC establishes new policies and regulations through policy statements and adjudications of individual pipeline matters. Further, additional changes to regulations may occur based on actions taken by the United States Congress and/or the courts. As to these various developments, the Managing General Partner has advised the Trust that Working Interest Owners have advised that the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.

        In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 and culminated in adoption of the Natural Gas Wellhead Decontrol Act that removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

        Sales of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be just and reasonable and may be derived in a number of ways including, but not limited to, the FERC's indexing methodology.

        As to these various types of regulation, the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.

State and Other Regulation

        State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements. Some states have implemented more stringent legislation in recent years to regulate gathering rates charged by gas gathering companies, but to date the effect on the Working Interests Owners in connection with the Trust has been minimal.

Environmental Regulations

General

        The Working Interest Owners' oil and gas activities on the Royalty Properties are subject to existing and evolving federal, state and local environmental laws and regulations. The Managing General Partner of the Partnership has advised the Trust that, with respect to the Royalty Properties, the Working Interest Owners believe that their operations and facilities are in general compliance with applicable health, safety, and environmental laws and regulations that have taken effect at the federal, state and local levels. In addition, events in recent years have heightened environmental concerns about the oil and gas industry generally, and about offshore operations in particular. The Working Interest Owners' operation of federal offshore oil and gas leases is subject to extensive governmental regulation, including regulations that may, in certain circumstances, impose absolute liability upon lessees for cost of removal of pollution and for pollution damages resulting from their operations, and require lessees to suspend or cease operations in the affected areas.

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        Under the Oil Pollution Act of 1990, as amended by the Coast Guard Authorization Act of 1996, (collectively, "OPA"), parties responsible for offshore facilities must establish and maintain evidence of oil-spill financial responsibility ("OSFR") for costs attributable to potential oil spills. OPA requires a minimum of $35 million in OSFR for offshore facilities located on the OCS. This amount is subject to upward regulatory adjustment up to $150 million. Responsible parties for more than one offshore facility are required to provide OSFR only for their offshore facility requiring the highest OSFR. In 1998, the Minerals Management Service (which in 2010 was renamed the Bureau of Ocean Energy Management, Regulation and Enforcement, and more recently reorganized into the Bureau of Safety and Environmental Enforcement and the Bureau of Ocean Energy Management, which we collectively refer to as "BOEM") adopted regulations for establishing the amount of OSFR required for particular facilities. The amount of OSFR increases as the volume of a facility's worst-case oil spill increases. Accordingly, for facilities with worst-case spills of less than 35,000 barrels, only $35 million in OSFR is required; for worst-case spills of over 35,000 barrels, $70 million is required; for worst-case spills of over 70,000 barrels, $105 million is required; and for worst-case spills of over 105,000 barrels, $150 million is required. In addition, all OSFR below $150 million remains subject to upward regulatory adjustment if warranted by the particular operational, environmental, human health or other risks involved with a facility. The Managing General Partner of the Partnership has advised the Trust that the Working Interest Owners are currently maintaining their required OSFR with respect to the Royalty Properties. Although the Managing General Partner of the Partnership has advised the Trust that current environmental regulation has had no material adverse effect on the Working Interest Owners' present method of operations with respect to the Royalty Properties, future environmental regulatory developments such as stricter environmental regulation and enforcement policies cannot presently be quantified. However, during 2010, drilling activity associated with the redevelopment of Eugene Island 339 was suspended, the drilling rig moved off location and the redevelopment plan modified given Chevron's inability to obtain drilling permits in a timely basis under new guidelines issued by the BOEM on June 8, 2010 pursuant to NTL No. 2010-N05, "Increased Safety Measures for Energy Development on the OCS" following the Deepwater Horizon incident.

        The Working Interest Owners' operations are subject to regulation, principally under the following federal statutes, along with their analogous state statutes.

Water

        The Federal Water Pollution Control Act of 1972, as amended, and the Oil Pollution Act of 1990 impose certain liabilities and penalties upon persons and entities, such as the Working Interest Owners, for any discharges of petroleum products in reportable quantities, for the costs of removing an oil spill, and for natural resource damages. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives in surface waters.

        The federal NPDES permits prohibit the discharge of produced water, sand and other substances related to the oil and gas industry to coastal waters of Louisiana and Texas. The Managing General Partner of the Partnership has advised the Trust that these costs have not had a material adverse impact on the Working Interest Owners' operations with respect to the Royalty Properties.

Air Emissions

        Amendments to the federal Clean Air Act were enacted in late 1990 and require most industrial operations in the United States, including offshore operations, to incur capital expenditures for air emission control equipment in connection with maintaining and obtaining operating permits and approvals addressing other air emission related issues. The Environmental Protection Agency ("EPA") and state environmental agencies have been developing regulations to implement these requirements. Some of the Working Interest Owners' facilities are included within the categories of hazardous air

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pollutant sources that will be affected by these regulations and these regulations could make operation of the Royalty Properties more costly.

Climate Change

        A variety of regulatory developments, proposals or requirements have been introduced that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. Among these developments is the Kyoto Protocol to the United Nations Framework Convention on Climate Change that became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently participating in the Protocol though the Protocol may impact oil and gas markets generally. In addition, Congress has considered recent proposed legislation directed at reducing greenhouse gas emissions. There has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources. In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gases are an "air pollutant" under the federal Clean Air Act and, thus, subject to future regulation. The Environmental Protection Agency (the "EPA") is moving forward to regulate greenhouse gases. The EPA has issued an "Endangerment Finding" final rule, effective January 14, 2010, which states that current and projected concentrations of six key greenhouse gases in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, allowing the EPA to finalize motor vehicle greenhouse gas standards effective January 2, 2011 (the effect of which could reduce demand for motor fuels refined from crude oil). According to the EPA, the motor vehicle greenhouse gas standards will trigger construction and operating permit requirements for stationary sources. As a result, the EPA issued regulations to tailor these programs such that only large stationary sources will be required to have air permits that authorize greenhouse gas emissions.

        In addition, the EPA issued a "Mandatory Reporting of Greenhouse Gases" final rule effective December 20, 2009, which established a new comprehensive scheme requiring operators of stationary sources in the United States emitting more than established annual thresholds of carbon dioxide equivalent greenhouse gases to inventory and report their greenhouse gas emissions annually. In November 2010, the EPA published a final rule expanding this reporting rule to onshore and offshore petroleum and natural gas systems.

        Laws, regulations, treaties or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on the future operations of the Royalty Properties if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on the Royalty Property operations. In addition to potential impacts on the Royalty Property operations directly or indirectly resulting from climate- change legislation or regulations, the Royalty Property operations also could be negatively affected by climate-change related physical changes or changes in weather patterns. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact the operations of the Royalty Properties.

Solid Waste

        The Working Interest Owners' operations may generate wastes that are subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA has limited disposal options for certain hazardous wastes and may adopt more stringent disposal standards for nonhazardous wastes. Furthermore, it is possible that some wastes that are currently classified as

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nonhazardous, perhaps including wastes generated during drilling and production operations, may in the future be designated as "hazardous wastes." Such changes in the regulations would result in more rigorous and costly disposal requirements that could result in increased operating expenses on the Royalty Properties.

Norm

        Oil and gas exploration and production activities have been identified as generators of low-level naturally-occurring radioactive materials ("NORM"). The generation, handling and disposal of NORM in the course of offshore oil and gas exploration and production activities is currently regulated in federal and state waters. These regulations could result in an increase in operating expenses on the Royalty Properties.

Superfund

        The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to the fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the current or previous owner and operator of a facility and companies that disposed or arranged for the disposal of the hazardous substance found at a facility. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs, which can be substantial, of such action. Although "petroleum" is excluded from CERCLA's definition of a "hazardous substance", in the course of their operations, the Working Interest Owners may generate wastes that fall within CERCLA's definition of "hazardous substances." The Working Interest Owners may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been disposed. Such clean-up costs may make operation of the Royalty Properties more expensive for the Working Interest Owners.

Offshore Operations

        Offshore oil and gas operations are subject to regulations of the United States Department of the Interior, or "DOI", including regulations promulgated pursuant to the Outer Continental Shelf Lands Act, which impose liability upon a lessee, such as the Working Interest Owners, under a federal lease for the cost of clean-up of pollution resulting from a lessee's operations. More specifically, the BOEM, regulates offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells and removal of facilities on the Outer Continental Shelf. On April 22, 2010, a deepwater U.S. Gulf of Mexico drilling rig, the Deepwater Horizon, sank after a blowout and fire at the Macondo wellsite. As a result, the DOI imposed a six-month moratorium on offshore deepwater drilling, which it lifted on October 12, 2010. Although the moratorium has been lifted, the Deepwater Horizon incident led to additional governmental regulation of the offshore exploration and production industry. The Department of the Interior may require a lessee under federal leases to suspend or cease operations in the affected areas.

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Item 1A.    Risk Factors.

        Although risk factors are described elsewhere in this Form 10-K together with specific forward-looking statements, the following is a summary of the principal risks associated with an investment in Units in the Trust.

The Trust continues to utilize its cash reserves to pay expenses, and there are not likely to be Net Proceeds distributed to the Trust for the foreseeable future. Because of the lack of receipt of Net Proceeds, the Trust has in the past not had sufficient cash flow to pay expenses on a current basis. While the Trust realized proceeds of approximately $1,485,851 from the sale in October 2011 by the Partnership of 20% of the Royalty, the Trust may in the future still not have sufficient cash flow to pay expenses on a current basis. As a result of such sale, the Partnership will receive in the future only 80% of the Net Proceeds if and when there are sufficient Net Proceeds for distribution on the Royalty. The Trustees may take certain actions on behalf of the Trust that could materially impact the Unit holders, including borrowing money, causing the sale by the Partnership of the remaining interests in the Royalty owned by the Partnership, selling all or any part of the Trust's interest in the Partnership or exercising the Trustees' rights to dissolve the Partnership.

        The Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. The Trust has not received a distribution of Net Proceeds since December 2008, and there are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. Because of the lack of receipt of Net Proceeds, the Trust has previously not had sufficient cash flow to pay expenses on a current basis.

        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. The Trustees also sought a loan to the Trust to be able to pay liabilities of the Trust. For more information, see "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" under Item 7 of this Form 10-K.

        On October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale of 20% of the Royalty. The sale generated $1,600,000 in gross proceeds and occurred as part of a previously announced 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 Partnership has retained an 80% interest in the Royalty, and thus the Partnership will receive in the future only 80% of the Net Proceeds when there are sufficient Net Proceeds for distribution on the Royalty.

        The Trust continues to utilize its cash reserves to pay expenses. As of December 31, 2011, those reserves were approximately $944,917, representing approximately 102% of the average annual expenses of the Trust during the three-year period ended December 31, 2011. It is anticipated that the existing cash reserves will be depleted during the first quarter of 2013.

        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 on behalf of the Trust that could materially impact the Unit holders. Such actions include borrowing money, causing a sale by the Partnership of all or a part of the Royalty owned by the Partnership, selling all or a part of the Trust's interest in the Partnership or exercising the Trustees' rights to dissolve the Partnership.

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Production from Eugene Island 339 and Ship Shoal 182 and 183, the two most significant Royalty Properties, ceased following damage inflicted by Hurricane Ike in September 2008. While oil and natural gas production at Ship Shoal 182 and 183 was restored in 2009, there can be no assurance that production will be restored at Eugene Island 339. Chevron's failure or inability to pursue redevelopment of Eugene Island 339, and on the timeframes previously approved by the BOEM, could result in a loss of the lease. Based on the damage caused by Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively impacted and there were no distributions during 2009, 2010, 2011 or the first quarter of 2012. If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest. Development activities may not generate sufficient additional revenue to repay such costs. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. As of October 31, 2011, development and production costs of the Royalty exceeded the proceeds of production from the Royalty Properties by approximately $5.9 million, net to the entire Royalty. Significant development and production costs may be incurred as Eugene Island 339 is redeveloped. Chevron has entered into a participation agreement whereby a third party would bear the costs of development of Eugene Island 339, but would earn an assignment of 65% of Chevron's working interest therein, thereby reducing the amount recoverable on the Royalty. See "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Operations and—Liquidity and Capital Resources" under Item 7 of this Form 10-K."

        The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike in September 2008. Chevron is working on the plugging and abandonment of the existing wells, clearing debris and otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the second quarter of 2012. Chevron has informed the Corporate Trustee that Chevron presently intends to pursue the redevelopment of platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the BOEM in response to Chevron's submission to the BOEM of a program to restore production at Eugene Island 339. Chevron has informed the Corporate Trustee that Chevron has received a Suspension of Production, or "SOP", from the BOEM, for Eugene Island 339 through August 31, 2012, as long as certain SOP milestones are met. The SOP provides for the staged redevelopment of Eugene Island 339 and the adjacent lease, Eugene Island 338 (which is not a property subject to the overriding royalty interest held by the Partnership), as a single development project, contingent upon meeting certain obligations established in the SOP. Chevron is required to provide the BOEM with periodic updates on Chevron's progress and to meet each of the SOP activity schedule deadlines to maintain 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, 2011, 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 SOP will be sought or if

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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 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 redevelopment of Eugene Island 339 under the terms of such participation agreement. The costs for the redevelopment plan would be significant. 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.

        If Production Costs of the Royalty exceed the Gross Proceeds from the Royalty Properties, the Trust will not receive Net Proceeds until future Gross Proceeds exceed the total of the Production Costs plus accrued interest. Development activities may not generate sufficient additional revenue to repay such costs. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to

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make distributions for some period of time in the future. As of October 31, 2011, Production Costs of the Royalty exceeded the Gross Proceeds 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 as of December 31, 2010; however, additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the terms of the Conveyance if, and when, Net Proceeds would otherwise be payable on the Royalty.

        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. 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.

        For additional information, see "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Operations." Based on the damage caused by Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively impacted and no distributions have been made to Unit holders since January 9, 2009. 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. At this time, the ultimate outcome of the various matters cannot be determined with any degree of certainty.

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

        On April 22, 2010, a deepwater U.S. Gulf of Mexico drilling rig, the Deepwater Horizon, sank after a blowout and fire at the Macondo wellsite. In response to such incident, the BOEM, among other

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things, issued Notices to Lessees, or "NTLs," implementing additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, imposed additional requirements with respect to development and production activities in the U.S. Gulf of Mexico and has delayed the approval of applications to drill in both deep-water and shallow-water areas.

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

Natural gas and oil prices fluctuate due to a number of factors, and lower prices will reduce Net Proceeds available to the Trust and distributions to Trust Unit holders.

        Net Proceeds and the Trust's quarterly distributions are highly dependent upon the prices realized from the sale of natural gas and oil. Natural gas and oil prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and the Working Interest Owners. Factors that contribute to price fluctuation include, among others:

•

political conditions worldwide, in particular political disruption, war and other armed conflict in oil producing regions such as North Africa and the Middle East;



•

worldwide economic conditions;



•

weather conditions;



•

the supply and price of foreign oil and natural gas;



•

the level of consumer demand;



•

the price and availability of alternative fuels;



•

the proximity to, and capacity of, transportation facilities; and



•

the effect of worldwide energy conservation measures.

        Moreover, government regulations, such as regulation of natural gas and oil transportation and price controls, can affect product prices in the long term.

        Crude oil prices have been volatile the last several years and, in 2011, ranged from a high of approximately $94.88 to a low of approximately $75.40. The Trust cannot predict the timing or the duration of any economic cycle and, depending on the prices realized, the financial condition of the Trust could be materially adversely affected.

        When natural gas and oil prices decline, the Trust is affected in two ways. First, net royalties are reduced. Second, exploration and development activities on the underlying properties may decline as some projects may become uneconomic and are either delayed or cancelled. The volatility of energy prices reduces the predictability of future cash distributions to Unit holders. Substantially all of the natural gas and natural gas liquids produced from the Royalty Properties operated by Chevron is being sold to Chevron Natural Gas at spot market prices. Substantially all of the crude oil produced by the Royalty Properties operated by Chevron is being sold to subsidiaries of Chevron Corporation based on pricing bulletins.

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Increased production and development costs for the Royalty could result in decreased or no Trust distributions.

        Production and development costs attributable to the Royalty are deducted in the calculation of the Trust's share of Net Proceeds. Production and development costs are impacted by increases in commodity prices both directly and indirectly, through commodity-price dependent costs such as electricity, and indirectly, as a result of demand-driven increases in costs of oilfield goods and services. Accordingly, higher or lower production and development costs, without concurrent increases in revenues, directly decrease or increase the amount received by the Trust for the Royalty.

        In September 2008, Hurricane Ike completely destroyed the platforms and wells on Eugene Island 339. Chevron is proceeding to plug and abandon the existing wells, to clear debris and otherwise to deal with the remaining infrastructure, with estimated costs to the Royalty relating thereto of approximately $18.7 million, approximately $18.1 million of which had been incurred through January 31, 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. 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. The costs for the redevelopment would be significant. Chevron has entered into a participation agreement whereby a third party would bear the costs of development of Eugene Island 339, but would earn an assignment of 65% of Chevron's working interest therein, thereby reducing the amount recoverable on the Royalty. At this time, there can be no assurance that production at Eugene Island 339 will be restored, or the impact of such restoration on Net Proceeds. For additional information, see "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Operations."

        If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest, at a rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs. Accordingly, there may not be sufficient Net Proceeds to make a particular distribution.

Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both estimates of reserves and estimated future revenues to be too high or too low.

        The value of the Units depends upon, among other things, the amount of reserves attributable to the Royalty and the estimated future value of the reserves. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions include:

•

historical production from the area compared with production rates from similar producing areas;



•

the assumed effect of governmental regulation;



•

assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures;



•

the availability of enhanced recovery techniques; and



•

relationships with landowners, working interest partners, pipeline companies and others.

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        Changes in these factors and assumptions can materially change reserve estimates and future net revenue estimates.

        The reserve quantities attributable to the Royalty and revenues are based on estimates of reserves and revenues for the Royal Properties. The method of allocating a portion of those reserves to the Trust is complicated because the Trust, indirectly through the Partnership, holds an interest in the Royalty and does not own a specific percentage of the reserves. Ultimately, actual production, revenues and expenditures for the Royalty Properties, and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-downs of reserves.

        The Trustees also rely entirely on reserve estimates and related information prepared by Chevron, the other Working Interest Owners and the independent reserve engineer engaged by the Partnership. While the Trustees have no reason to believe the reserve estimates included in this Form 10-K are inaccurate, to the extent additional information exists that could affect the reserve estimates of Chevron, the other Working Interest Owners and the independent reserve engineer, the estimated reserves in this Form 10-K could also be too low.

Operating risks for the Working Interest Owners' interests in the Royalty Properties can adversely affect the Royalty and Trust distributions.

        There are operational risks and hazards associated with the production and transportation of natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of natural gas, releases of other hazardous materials, mechanical failures, cratering and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment of natural resources, or cleanup obligations. The occurrence of drilling, production or transportation accidents and natural disasters at any of the Royalty Properties will reduce Trust distributions by the amount of uninsured costs. These accidents may result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Offshore activities are also subject to a variety of additional operating risks, such as hurricanes and other weather disturbances. Any uninsured costs would be deducted as a production cost in calculating net proceeds payable to the Trust.

        As described in this report, production from the two most significant oil and gas properties associated with the Trust ceased following damage inflicted by Hurricane Ike in September 2008. The platforms and wells on Eugene Island 339 were completely destroyed. While Hurricane Ike caused limited damage to the facilities at Ship Shoal 182 and 183, all of the wells at Ship Shoal 182 and 183 were shut-in following hurricane related damage to a third-party transporter's natural gas pipeline.

Terrorism and hostilities in the Middle East could decrease Trust distributions or the market price of the units of beneficial interest of the Trust.

        Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism and other sustained military campaigns could adversely affect Trust distributions or the market price of the Units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in natural gas prices, or the possibility that the infrastructure on which the operators developing the underlying properties rely could be a direct target or an indirect casualty of an act of terror.

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The operators of the working interests are subject to extensive governmental regulation.

        Offshore oil and gas operations have been, and in the future will be, affected by federal, state and local laws and regulations and other political developments, such as price or gathering rate controls and environmental protection regulations. These regulations and changes in regulations could have a material adverse effect on Royalty income payable to the Trust.

Regulation of greenhouse gases and climate change could adversely affect Trust distributions

        Some scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases and including carbon dioxide and methane, may be contributing to the warming of the Earth's atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of greenhouse gas emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. Legislative and regulatory measures to address concerns that emissions of greenhouse gases are contributing to climate change are in various phases of discussions or implementation at the international, national, regional and state levels.

        The EPA is taking steps that would result in the regulation of greenhouse gases as pollutants under the Clean Air Act. The EPA has issued an "Endangerment Finding" final rule, effective January 14, 2010, which states the current and projected concentrations of six key greenhouse gases in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, that threaten public health and welfare, and allowed the EPA to finalize motor vehicle greenhouse gas standards effective January 2, 2011 (the effect of which could reduce demand for motor fuels refined from crude oil). According to the EPA, the final motor vehicle greenhouse gas standards trigger construction and operating permit requirements for stationary sources. As a result, the EPA has proposed to tailor these programs such that only large stationary sources will be required to have air permits that authorize greenhouse gas emissions. In addition, the EPA has issued a "Mandatory Reporting of Greenhouse Gases" final rule, effective December 29, 2009, which establishes a new comprehensive scheme requiring operators of stationary sources in the United States emitting more than established annual thresholds of carbon dioxide-equivalent greenhouse gases to inventory and report their greenhouse gas emissions annually. In November 2010, the EPA published a final rule expanding this reporting rule to onshore and offshore petroleum and natural gas systems beginning in 2012 for emissions in 2011.

        Existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on the Royalty Property operations if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on the Royalty Property operations. In addition to potential impacts on the Royalty Property operations directly or indirectly resulting from climate- change legislation or regulations, the Royalty Property operations also could be negatively affected by climate-change related physical changes or changes in weather patterns.

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.

        Neither the Trustees nor the Unit holders can influence or control the operation or future development of the underlying properties. The Royalty Properties are owned by independent Working Interest Owners. The Working Interest Owners manage the underlying properties and handle receipt and payment of funds relating to the Royalty Properties and payments to the Trust for the Royalty.

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        Information regarding operations provided by the Working Interest Owners has been subject to errors and adjustments, some of which have been significant. Accordingly, the Trustees cannot assure Unit holders that other errors or adjustments by Working Interest Owners, whether historical or future, will not affect future Royalty income and distributions by the Trust.

        The current Working Interest Owners are under no obligation to continue operating the properties. The failure of an operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable to the Trust. Neither the Trustees nor the Unit holders have the right to replace an operator.

The Trustees rely upon the Working Interest Owners and Managing General Partner for information regarding the Royalty Properties.

        The Trustees rely on the Working Interest Owners and the Managing General Partner of the Partnership for information regarding the Royalty Properties. The Working Interest Owners alone control (i) historical operating data, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures, (iii) geological data relating to reserves, as well as related projections regarding production, operating expenses and capital expenses used in connection with the preparation of the reserve study, (iv) forward-looking information relating to production and drilling plans and (v) information regarding the Royalty Properties responsive to litigation claims. While the Trustees request material information for use in periodic reports as part of its disclosure controls and procedures, the Trustees do not control this information and rely entirely on the Working Interest Owners to provide accurate and timely information when requested for use in the Trust's periodic reports. The Trustees also rely on the Managing General Partner of the Partnership to collect certain information from the Working Interest Owners and do not have any direct contact with the Working Interest Owners other than the Managing General Partner. Under the terms of the Trust Indenture, the Trustees are entitled to rely, and in fact rely, on certain experts in good faith. While the Trustees have no reason to believe their reliance on experts is unreasonable, this reliance on experts and limited access to information may be viewed as a weakness as compared to the management and oversight of entity forms other than trusts.

The owner of any Royalty Property may abandon any property, terminating the related Royalty.

        The Working Interest Owners may at any time transfer all or part of the Royalty Properties to another unrelated third-party. Unit holders are not entitled to vote on any transfer, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the Royalty Properties will continue to be subject to the Royalty, but the Net Proceeds from the transferred property would be calculated separately and paid by the transferee. The transferee would be responsible for all of the obligations relating to calculating, reporting and paying to the Trust the Royalty on the transferred portion of the Royalty Properties, and the current owner of the Royalty Properties would have no continuing obligation to the Trust for those properties.

        The current Working Interest Owners or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in termination of the Royalty relating to the abandoned well.

        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,

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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 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.

The Royalty can be sold and the Trust can be terminated.

        The Trust will be terminated and the Trustees must sell the Royalty if holders of a majority of the Units approve the sale or vote to terminate the Trust, or if the total future net revenues attributable to the Royalty, determined by the independent reserve engineer as of December 31 of the prior year, are less than $2 million. Following any such termination and liquidation, the net proceeds of any sale will be distributed to the Unit holders and Unit holders will receive no further distributions from the Trust. In addition, if the Trust does not have sufficient funds to pay the liabilities of the Trust, the Trustees may take certain actions on behalf of the Trust that could materially impact the Unit holders. Such actions include borrowing money, selling all or a part of the Trust's interest in the Partnership, exercising their rights to dissolve the Partnership or causing a sale by the Partnership of the Royalty owned by the Partnership.

        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

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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 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., as 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% is 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.

        For more information, see "—Termination of the Trust" under Item 1 of this Form 10-K and "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" under Item 7 of this Form 10-K.

Trust assets are depleting assets and, if the Working Interest Owners or other operators of the Royalty Properties do not perform additional development projects, the assets may deplete faster than expected.

        The Net Proceeds payable to the Trust are derived from the sale of depleting assets. Accordingly, the portion of the distributions to Unit holders attributable to depletion may be considered a return of capital. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the Royalty Properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of natural gas. If operators of the Royalty Properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust. For federal income tax purposes, depletion is reflected as a deduction, which is dependent upon the purchase price of a Units. Please see the section entitled "—Description of the Units—Federal Income Tax Matters" under Item 1 of this Form 10-K.

        Because the Net Proceeds payable to the Trust are derived from the sale of depleting assets, the portion of distributions to Unit holders attributable to depletion may be considered a return of capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the Unit holders, which could reduce the market value of the Units over time. Eventually, properties underlying the Trust's Royalty will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of Net Proceeds therefrom.

Unit holders have limited voting rights.

        Voting rights as a Unit holder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unit holders or for an annual or other periodic re-election of the Trustees. Additionally, Unit holders have no voting rights in the Working Interest Owners. Unlike corporations, which are generally governed by boards of directors elected by their equity holders, the Trust is administered by a Corporate Trustee and three Individual

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Trustees in accordance with the Trust Agreement and other organizational documents. The Trustees have extremely limited discretion in their administration of the Trust.

Unit holders have limited ability to enforce the Trust's rights against the current or future owners of the Royalty Properties.

        The Trust Agreement and related trust law permit the Trustees and the Trust to sue the Working Interest Owners to compel them to fulfill the terms of the Conveyance of the Royalty. If the Trustees do not take appropriate action to enforce provisions of the Conveyance, the recourse of a Unit holder would likely be limited to bringing a lawsuit against the Trustees to compel the Trustees to take specified actions. Unit holders probably would not be able to sue the Working Interest Owners directly.

Item 1B.    Unresolved Staff Comments.

        There were no unresolved Securities and Exchange Commission comments as of December 31, 2011.

Item 2.    Properties.

        Reference is made to Item 1 of this Form 10-K.

Item 3.    Legal Proceedings.

        Currently, there are not any legal proceedings pending to which the Trust is a party or of which any of its property is the subject.

Item 4.    Mine Safety Disclosures

        Not applicable.

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PART II

Item 5.    Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchasers of Equity Securities.

        Effective January 3, 2011, the Units have been quoted on the OTCQB™ Marketplace, which is an electronic quotation service operated by Pink OTC Markets Inc. for securities traded over-the-counter. Prior to January 3, 2011, the Trust Units were traded on the Nasdaq Capital Market under the symbol "TELOZ". At March 29, 2012, the 4,751,510 Units outstanding were held by 1,703 Unit holders of record. The high and low sales price as reported by the Nasdaq Capital Market through December 31, 2010 and from and after January 3, 2011, the high and low bid quotations obtained from data available on the Yahoo! Finance website, and distributions for each quarter for the years ended December 31, 2011 and 2010, were as follows. The over-the-counter quotations reflect inter-dealer prices, without retail mark-up, markdown or commissions, and may not represent actual transactions.

        See "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Operations" and "—Liquidity and Capital Resources" and Note 4 to Notes to Financial Statements under Item 8 of this Form 10-K for a discussion regarding uncertainty of distributions.

Item 6.    Selected Financial Data.

Item 7.    Trustee's Discussion and Analysis of Financial Condition and Results of Operation.

        On the last business day of each calendar quarter, the Working Interest Owners pay to the Partnership 20% of the Net Proceeds (which represents the Partnership's 80% interest in 25% of the Net Proceeds) for the immediately preceding Quarterly Period; prior to the sale by the Partnership of 20% of the Royalty which was effective August 1, 2011, the Working Interest Owners would pay to the Partnership 25% of the Net Proceeds from the then 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 December 31, 2011 would substantially represent the revenues and expenses from the Royalty Properties from August

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through October 2011. The financial and operating information included in this Form 10-K for the 12 months ended December 31, 2011 primarily represents financial and operating information with respect to the Royalty Properties for the months of November 2010 through October 2011. Similarly, the financial and operating information included in this Form 10-K for the 12 months ended December 31, 2010 primarily represents financial and operating information with respect to the Royalty Properties for the months of November 2009 through October 2010. Similarly, the financial and operating information included in this Form 10-K for the 12 months ended December 31, 2009 primarily represents financial and operating information with respect to the Royalty Properties for the months of November 2008 through October 2009. Income from the Royalty is recorded by the Trust on a cash basis, when it is received by the Trust from the Partnership.

New Accounting Pronouncements

        There were no accounting pronouncements issued during the year ended December 31, 2011 applicable to the Trust or its financial statements.

Critical Accounting Policies

        Basis of Accounting:    The Trust's 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 financial statements and those prepared in accordance with GAAP are:

(a)

Royalty income from net profits 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 (c);



(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 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 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 financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles, Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income. 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.

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        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.

        Oil and Gas Reserves.    The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices and production costs, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from estimates.

        The standardized measure of discounted future net cash flows is prepared using assumptions made pursuant to FASB and SEC guidelines. Such assumptions include using average fiscal-year oil and gas prices(calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month reporting period) and year-end costs for estimated future production expenditures. Discounted future net cash flows are calculated using a 10% discount rate. Changes in any of these assumptions could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.

        Amortization of Overriding Royalty Interest.    The Trust amortizes the investment in overriding royalty 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.

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.

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        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 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 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% is 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.

        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 12 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

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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 second quarter of 2012. Chevron has informed the Corporate Trustee that Chevron presently intends to pursue the redevelopment of platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the BOEM in response to Chevron's submission to the BOEM of a program to restore production at Eugene Island 339; however, there is no obligation for Chevron to pursue such redevelopment. The costs for 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 redevelopment of Eugene Island 339 under the terms of such participation agreement. See "—Operations" for a more detailed discussion of Eugene Island 339.

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

        In addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. Chevron 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 "—Operations" for a more detailed discussion of West Cameron 643 and East Cameron 371.

        Future Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the operators of the Royalty Properties. 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

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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 second 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. 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 $18.1 million of which had been incurred through January 31, 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 exceed the total of the excess costs plus accrued interest at a rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net Proceeds since December 2008. As of October 31, 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 "—Operations."

        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.

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        The reserve amount at December 31, 2011 and 2010 was $944,917 and $352,017, respectively. As described herein, there are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. Because of the lack of receipt of Net Proceeds, the Trust, prior to the sale of 20% of the Royalty by the Partnership, did not have sufficient cash flow to pay expenses on a current basis.

        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 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 further 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 sale of a portion of the Royalty by the Partnership in late October 2011.

        The accompanying 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 financial statements. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. See Notes 3 and 6 to the financial statements.

Operations

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

        The platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike in September 2008. Crude oil revenues from Eugene Island 339 represented approximately 48% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 47% of such revenues for the nine months ended September 30, 2008. Eugene Island 339 contributed approximately 12% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 41% of such revenues for the nine months ended September 30, 2008. Based on a prior year reserve study prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants, Eugene Island 339 accounted for approximately 34% of the total future net revenues attributable to the

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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 second 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. 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 $18.1 million of which had been incurred through January 31, 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 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

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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. See "Risk Factors" under Item 1A of this Form 10-K.

        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

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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.

        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 May 2007, the Trust engaged an independent oil and gas accounting firm for the purpose of reviewing the books and records of certain Working Interest Owners with respect to the Royalty Properties and the related payments to the Trust. As part of this audit review process, certain adjustments to revenues, production volumes, prices and capital expenditures have occurred, and references below to a prior period audit adjustment, or an audit of prior periods, refers to the audit described in this paragraph or in the following paragraph. We include discussions of audit adjustments in the comparison of year 2009 because, as a result of such audit adjustments, certain of the Royalty Properties, including Eugene Island 339, have positive oil and gas volumes for 2009 (and the revenues associated therewith), despite there being no actual oil or gas production at such properties due to damages inflicted by Hurricane Ike in September 2008.

        In January 2010, the Trust engaged the same independent oil and gas accounting firm to review the books and records of certain Working Interest Owners with respect to the Royalty Properties and the related payments to the Trust. Such audit review process is currently on-going and may result in certain adjustments to revenues, production volumes, prices and expenditures. As part of such process, Chevron agreed that $22,197 in adjustments were appropriate, which were credited in the first quarter of 2011. 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.

Years 2011 and 2010

Royalty Trust Comparison

        Royalty income was $0 in 2010 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.

        On October 27, 2011, but effective as of August 1, 2011, the Partnership consummated a sale to a third party of 20% of the Royalty for $1,600,000 in gross proceeds. The Trust received a distribution from the Partnership of approximately $1,485,851, representing 99.99% of the net proceeds from the

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sale of $1,486,000. The proceeds were used to pay for Trust expenses and to increase the reserve for future Trust expenses.

        General and administrative expenses for the Trust were $894,113 for 2011 compared to $911,245 for 2010. The decrease in expenses in 2011 is due primarily to the timing of the recording of expenses.

        The reserve for future Trust expenses increased approximately $591,000 which represents the excess cash received from the sale of 20% of the Royalty after payment for Trust expenses.

        There was no distributable income for 2011 and therefore no distributions to unit holders.

        For 2011, the Trust had undistributed net loss of $2,162,703, representing the Trust's portion of the undistributed net loss of $10,813,516 associated with the Royalty Properties for 2011. The cumulative net loss for the Trust was $4.7 million as of December 31, 2011. For 2010, the Trust had an undistributed net loss of $1,537,061. 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

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

Natural Gas and Gas Products

        Natural gas revenues and gas products decreased approximately 50% from $1,756,145 in 2010 to $871,255 in 2011, due primarily to decreased production at Ship Shoal 182/183. Gas and gas products volumes decreased 42% from 327,444 Mcf equivalents in 2010 to 190,528 Mcf equivalents in 2011. Production ceased at Ship Shoal 182/183 for 36 days starting in late March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Ship Shoal was again shut-in during November 2010 for a tank replacement and production slowly returned thereafter. The decrease in volumes is also partially due to an adjustment that was made to correct and increase volumes and values reported in a prior quarter as well as normal fluctuations in production. The average price received for natural gas decreased approximately 14% from an average price of $5.05 per Mcf in 2010 to $4.33 per Mcf in 2011.

Crude Oil and Condensate

        Crude oil and condensate revenues increased 24% from $13,130,251 in 2010 to $16,255,926 in 2011, due primarily to increased realized prices. Oil volumes decreased 9% from 168,985 barrels in 2010 to 153,319 barrels in 2011. Production ceased at Ship Shoal 182/183 for 36 days starting in late March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Ship Shoal was again shut-in during November 2010 for a tank replacement and production slowly returned thereafter. The average price received for crude oil and condensate increased 36% from $77.70 in 2010 to $106.03 in 2011.

Operating and Capital Expenditures

        Operating expenses paid by the Working Interest Owners increased 11% from $23,921,129 in 2010 to $26,576,911 in 2011, due primarily to increased well and platform abandonment work being conducted at Eugene Island 339 in 2011 as compared to 2010. Reflected within the operating expenses are management fees to Chevron, as Managing General Partner of the Partnership, of $1,172,039 and $1,309,488 for 2010 and 2011, respectively.

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        Capital expenditures paid by the Working Interest Owners decreased 10% from $1,399,182 in 2010 to $1,254,982 in 2011. The capital expenditures during 2010 related primarily to platform upgrades and repairs at Ship Shoal 182/183. The capital expenditures during 2011 related primarily to tank and panel upgrades at Ship Shoal 182/183.

Special Cost Escrow Account

        The special cost escrow account is an account of the Working Interest Owners, and it is described herein for information purposes only. The Conveyance provides for the reserve of funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on 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, $1,579 and $7,946 in 2011 and 2010, respectively, 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 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. 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-K 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 December 31, 2011, $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 to the estimates and factors described above. Such deposits could result in a significant reduction to Royalty income for the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.

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Summary By Property

        Listed below is a summary of 2011 operations as compared to 2010 of the principal Royalty Properties based on gross revenues generated during these periods combined.

Eugene Island 339

        Eugene Island 339 crude oil revenues decreased $82,992, from $82,992 in 2010 to $0 in 2011, due to a decrease in crude oil volumes from 797 barrels in 2010 to 0 barrels in 2011. However, there was no actual crude oil production during 2010 and such crude oil revenues and production volumes are entirely from audit adjustments made in the fourth quarter of 2010 and associated with prior periods. Gas revenues decreased $128,822, from $128,822 in 2010 to $0 in 2011. Gas production was 15,055 Mcf in 2010 and 0 Mcf in 2011. However, there was no actual gas production during 2010 and such gas revenues and volumes are entirely from audit adjustments made in the fourth quarter of 2010 associated with prior periods. Capital expenditures increased from $(8,582) in 2010 to $0 in 2011. Capital expenditures for 2010 reflect credits of $8,582 associated with the workover of a well during a prior period and an invoice correction related to well abandonment. Operating expenses increased from $18,634,670 in 2010 to $20,883,713 in 2011 due primarily to more well and platform abandonment work being conducted at Eugene Island 339 in 2011 as compared to 2010.

        Production from Eugene Island 339 ceased following damage inflicted by Hurricane Ike in September 2008, as the platforms and wells on Eugene Island 339 were completely destroyed. Chevron is working on the plugging and abandonment of the existing wells, clearing debris and otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the second quarter of 2012. Chevron has informed the Corporate Trustee that Chevron presently intends to pursue the redevelopment of platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the BOEM in response to Chevron's submission to the BOEM of a program to restore production at Eugene Island 339. At this point in time, there can be no assurance that production will be restored at Eugene Island 339. See "—Operations."

Ship Shoal 182/183

        Ship Shoal 182/183 crude oil revenues increased from $12,590,657 in 2010 to $15,739,750 in 2011, primarily due to an increase in average crude oil prices received from $77.66 per barrel in 2010 to $106.09 per barrel in 2011. This increase was partially offset by a decrease in net crude oil production from 162,121 barrels in 2010 to 148,362 in 2011. The revenues and volumes for 2010 reflect an audit adjustment made in the fourth quarter of 2010, which resulted in the recognition of $10,188 in oil revenues from a prior period. Production ceased at Ship Shoal 182/183 for 36 days starting in late March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Ship Shoal was again shut-in during November 2010 for a tank replacement and production slowly returned thereafter. Gas revenues decreased from $1,296,622 in 2010 to $691,093 in 2011. Gas production decreased from 265,508 Mcf in 2010 to 162,286 Mcf in 2011 partially due to a scheduled platform shut in during the first quarter of 2011 and normal fluctuations in productions. The average natural gas sales price decreased from $4.88 per Mcf in 2010 to $4.26 in 2011. Capital expenditures decreased from a balance of $1,329,005 in 2010 to $1,198,250 in 2011 and were primarily associated with platform upgrades and repairs during 2011. Operating expenses increased from $3,904,099 in 2010 to $4,342,447 in 2011 primarily due to a routine wireline support expense project and workover expenses associated with the I-4 ST well.

        Production from Ship Shoal 182 and 183 ceased following damage inflicted by Hurricane Ike in September 2008. While Hurricane Ike caused limited surface damage to the facilities at Ship Shoal 182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. A limited volume of oil production was restored in

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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 for additional repairs. Production sales for both oil and natural gas at Ship Shoal 182/183 were restored on October 8, 2009 following completion of such additional repairs. Oil and gas production at Ship Shoal 182/183 ceased in March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Such oil pipeline has since been repaired and Ship Shoal 182/183 was reopened on May 1, 2010 after a 36-day shut-in. In November 2010, the platform at Ship Shoal 182/183 was shut-in for a scheduled tank replacement and production has slowly returned thereafter. See "—Operations."

South Timbalier 36/37

        South Timbalier 36/37 oil revenues increased from $346,870 in 2010 to $500,944 in 2011 due to an increase in realized prices. The average crude oil price was $76.64 per barrel in 2010 compared to $105.41 per barrel in 2011.There was also an increase in crude oil production from 4,526 barrels in 2010 to 4,752 barrels in 2011. Gas revenues decreased from $48,391 in 2010 to $ 48,073 in 2011.. There was an increase in natural gas volumes from 10,094 Mcf in 2010 to 11,224 Mcf in 2011. The average gas sales price realized was $4.79 per Mcf in 2010 and $4.28 per Mcf in 2011. Capital expenditures decreased from $78,759 in 2010 to $56,730 in 2011. Operating expenses increased $4,095 from $37,168 in 2010 to $41,263 in 2011.

Eugene Island 342

        Eugene Island 342 oil revenues decreased from $109,729 in 2010 to $15,232 in 2011. There was 1,541 barrels in crude oil production in 2010 and 206 barrels in 2011 Gas revenues increased from $9,926 in 2010 to $40,297 in 2011. Natural gas volumes were 2,924 Mcf in 2010 and 6,647 Mcf in 2011. There was no production in 2011 due to the field being shut in and all revenue mentioned above is due to a prior period accounting adjustment.

        The Eugene Island 342 Field has been shut-in during 2011 because the third-party pipeline from the Field was shut down due to a leak. Apache Corporation, who is the operator of Eugene Island 342 is currently working on obtaining permits to construct an alternate interconnect which, upon completion, is expected to bring production back online around May 2012.

West Cameron 643

        Production from West Cameron 643 ceased following damage inflicted by Hurricane Ike in September 2008 to a third-party transporter's pipeline. The lease for West Cameron 643 expired on May 31, 2010. West Cameron 643 gas revenues were $0 in 2010 and in 2011, as there was no gas production during 2010 or 2011. Operating expenses increased from $173,152 in 2010 to $5,054,130 in 2011 and are associated with abandonment costs at West Cameron 643. Capital expenditures were $0 in 2010 and 2011. The Net Proceeds with respect to Hilcorp'sownership of West Cameron 643 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 this property; and any excess Production Costs associated with this property are not expected to be taken into account with respect to the calculation of Net Proceeds with respect to the other Royalty Properties. See "—Operations."

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East Cameron 371

        Production from East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to a third-party transporter's pipeline. 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. There were no gas revenues or oil revenues during 2010 or 2011, as there was no production during these time periods. 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 this property; and any excess Production Costs associated with this property are not expected to be taken into account with respect to the calculation of Net Proceeds with respect to the other Royalty Properties. See "—Operations."

Years 2010 and 2009

Royalty Trust Comparison

        Royalty income was $0 in 2009 and 2010 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 approximately $911,245 for 2010 compared to $971,545 for 2009. The decrease in expenses in 2010 is due primarily to the timing of the recording of expenses.

        The reserves for future Trust expenses decreased approximately $911,000 due to the use of reserves from 2009 to pay for Trust expenses as there was no royalty income received in 2010.

        There was no distributable income for 2010 and therefore no distributions to unit holders.

        For 2010, the Trust had undistributed net loss of $1,537,061, representing the Trust's portion of the undistributed net loss of $6,154,398 associated with the Royalty Properties for 2010. The cumulative net loss for the Trust was approximately $3.5 million as of December 31, 2010. For 2009, the Trust had undistributed net loss of $5,469,255. 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.

Underlying Properties Comparsion

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

Natural Gas and Gas Products

        Natural gas revenues and gas products increased 14% from $1,538,011 in 2009 to $1,756,145 in 2010, due primarily to increased production at Ship Shoal 182/183. Gas and gas products volumes increased from 296,309 Mcf equivalents in 2009 to 327,444 Mcf equivalents in 2010. The revenues and volumes for 2009 reflect net credits of $808,484 in revenues and 127,711 Mcf of gas for prior period adjustments. The average price received for natural gas increased 3% from $4.90 per Mcf in 2009 to

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$5.05 Mcf in 2010. Prior to taking into account such adjustments to revenues and volumes, the average price received for natural gas would have been $3.55 per Mcf in 2009.

Crude Oil and Condensate

        Crude oil and condensate revenues increased 37% from $9,564,082 in 2009 to $13,130,251 in 2010, due primarily to increased production at Ship Shoal 182/183 and increased realized prices. Oil volumes increased 6.86% from 158,137 barrels in 2009 to 168,985 barrels in 2010. The revenues and volumes for 2009 reflect a credit associated with an audit for prior periods for $224,511 in revenues and 311 barrels. The average price received for crude oil and condensate increased 28% from $60.48 in 2009 to $77.70 in 2010. Prior to taking into account such adjustments to revenues and volumes, the average price received for crude oil and condensate would have been $59.18 per barrel in 2009.

Operating and Capital Expenditures

        Operating expenses paid by the Working Interest Owners decreased 26% from $32,226,146 in 2009 to $23,921,129 in 2010, due primarily to less well and platform abandonment work being conducted at Eugene Island 339 in 2010 as compared to 2009. Reflected in the operating expenses for 2009 are cost allocation refunds of a net aggregate of $115,253 for certain prior period adjustments. Reflected within the operating expenses are management fees to Chevron, as Managing General Partner of the Partnership, of $1,281,318 and $1,172,039 for 2009 and 2010, respectively.

        Capital expenditures paid by the Working Interest Owners increased 58% from $883,470 in 2009 to $1,399,182 in 2010. The capital expenditures during 2009 related primarily to repair of damages caused by Hurricane Ike in September 2008. The capital expenditures during 2010 related primarily to platform upgrades and repairs at Ship Shoal 182/183. Reflected in the capital expenditures for 2009 is a refund of $59,794 for certain prior period audit adjustments.

Special Cost Escrow Account

        In 2009, no funds were released from or deposited into the Special Cost Escrow account. As of December 31, 2009, approximately $4,306,275 remained in the Special Cost Escrow Account. 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 December 31, 2010 was approximately $3.5 million, net to the 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.

        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 to the estimates and factors described above. Such deposits could result in a significant reduction to Royalty income for the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.

Summary By Property

        Listed below is a summary of 2010 operations as compared to 2009 of the principal Royalty Properties based on gross revenues generated during these periods combined.

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Eugene Island 339

        Eugene Island 339 crude oil revenues increased $44,448, from $38,544 in 2009 to $82,992 in 2010, due to an increase in crude oil volumes from 318 barrels in 2009 to 797 barrels in 2010. However, there was no actual crude oil production during 2009 or 2010 and such crude oil revenues and production volumes are entirely from audit adjustments made in the first quarter of 2009 and the fourth quarter of 2010 and associated with prior periods. Gas revenues decreased $41,409, from $170,231 in 2009 to $128,822 in 2010. Gas production was 33,296 Mcf in 2009 and 15,055 Mcf in 2010. However, there was no actual gas production during 2009 or 2010 and such gas revenues and volumes are entirely from audit adjustments made in the first quarter of 2009 and the fourth quarter of 2010 associated with prior periods. Capital expenditures decreased from $246,729 in 2009 to $(8,582) in 2010. The higher capital expenditures during 2009 reflect costs associated with damages caused by Hurricane Ike. Capital expenditures for 2010 reflect credits of $8,582 associated with the workover of a well during a prior period and an invoice correction related to well abandonment. Operating expenses decreased from $26,866,150 in 2009 to $18,634,670 in 2010 due primarily to less well and platform abandonment work being conducted at Eugene Island 339 in 2010 as compared to 2009.

        Production from Eugene Island 339 ceased following damage inflicted by Hurricane Ike in September 2008, as the platforms and wells on Eugene Island 339 were completely destroyed. Chevron is working on the plugging and abandonment of the existing wells, clearing debris and otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the second quarter of 2012. Chevron has informed the Corporate Trustee that Chevron presently intends to pursue the redevelopment of platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the BOEM in response to Chevron's submission to the BOEM of a program to restore production at Eugene Island 339. At this point in time, there can be no assurance that production will be restored at Eugene Island 339. See "—Operations."

Ship Shoal 182/183

        Ship Shoal 182/183 crude oil revenues increased from $9,052,477 in 2009 to $12,590,657 in 2010, primarily due to an increase in net crude oil production from 152,725 barrels in 2009 to 162,121 in 2010 and an increase in average crude oil prices received. Average crude oil prices increased from $59.27 per barrel in 2009 to $77.66 per barrel in 2010. The revenues and volumes for 2010 reflect an audit adjustment made in the fourth quarter of 2010, which resulted in the recognition of $10,188 in oil revenues from a prior period. Gas revenues increased from $1,160,602 in 2009 to $1,296,622 in 2010. Gas production increased from 233,142 Mcf in 2009 to 265,508 Mcf in 2010. The revenues and volumes for 2009 reflect an audit adjustment made in the first quarter of 2009, which resulted in the recognition of $725,720 in gas revenues associated with 107,416 Mcf of gas from a prior period. The average natural gas sales price increased from $3.46 per Mcf in 2009, excluding the audit adjustment made during 2009, to $4.88 in 2010. Capital expenditures increased from a balance of $556,872 in 2009 to $1,329,005 in 2010 primarily due to platform upgrades and repairs during 2010. Operating expenses increased from $3,076,853 in 2009 to $3,904,099 in 2010 due to an unsuccessful well workover during the third quarter of 2010 and continuing repair costs related to damages inflicted by Hurricane Ike.

        Production from Ship Shoal 182 and 183 ceased following damage inflicted by Hurricane Ike in September 2008. While Hurricane Ike caused limited surface damage to the facilities at Ship Shoal 182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. 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 for additional repairs. Production sales for both oil and natural gas at Ship Shoal 182/183 were restored on October 8, 2009 following completion of such

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additional repairs. Oil and gas production at Ship Shoal 182/183 ceased in March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Such oil pipeline has since been repaired and Ship Shoal 182/183 was reopened on May 1, 2010 after a 36-day shut-in. In November 2010, the platform at Ship Shoal 182/183 was shut-in for a scheduled tank replacement. See "—Operations."

South Timbalier 36/37

        South Timbalier 36/37 oil revenues increased from $269,554 in 2009 to $346,870 in 2010 due to an increase in realized prices. There was a decrease in crude oil production from 4,859 barrels in 2009 to 4,526 barrels in 2010. The average crude oil price was $55.48 per barrel in 2009 compared to $76.64 per barrel in 2010. Gas revenues increased from $40,425 in 2009 to $48,391 in 2010 primarily due to increased production and an increase in realized prices. There was an increase in natural gas volumes from 9,024 Mcf in 2009 to 10,094 Mcf in 2010. Gas volumes for 2009 reflect a debit of 164 Mcf in 2009. The average gas sales price realized was $4.49 per Mcf in 2009 and $4.79 per Mcf in 2010. Capital expenditures increased from $(55,422) in 2009 to $78,759 in 2010. The capital expenditures in 2009 reflect a $56,263 credit related to a prior period audit adjustment. Operating expenses increased $41,731 from $(4,563) in 2009 to $37,168 in 2010. The operating expenses in 2009 reflect a $36,992 credit in 2009 related to a prior period audit adjustment.

Eugene Island 342/343

        Eugene Island 342/343 oil revenues increased from $17,545 in 2009 to $109,729 in 2010 due to an increase in both production and realized prices. There was an increase in crude oil production from 228 barrels in 2009 to 1,541 barrels in 2010. Gas revenues increased from $5,951 in 2009 to $9,926 in 2010 primarily due to increased production and an increase in realized prices. Natural gas volumes increased from 927 Mcf in 2009 to 2,924 Mcf in 2010. On the date of this Form 10-K, Apache Corporation is the operator of Eugene Island 342/343.

West Cameron 643

        Production from West Cameron 643 ceased following damage inflicted by Hurricane Ike in September 2008 to a third-party transporter's pipeline. The lease for West Cameron 643 expired on May 31, 2010. West Cameron 643 gas revenues were ($87,518) in 2009 as compared to $0 in 2010. There was no gas production during 2009 or 2010 and the revenues for 2009 (and the associated volumes of (13,001) Mcf) are a result of debits to correct an error in revenue allocation in August 2008. Operating expenses decreased from $1,006,626 in 2009 to $173,152 in 2010. Capital expenditures decreased from $135,291 in 2009 to $0 in 2010. See "—Operations."

East Cameron 371

        Production from East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to a third-party transporter's pipeline. 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. There were no gas revenues or oil revenues during 2009 or 2010, as there was no production during these time periods. See "—Operations."

Production and Price Review

        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

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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.

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.

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Contractual Obligations

        As of December 31, 2011, the Trust had no obligations or commitments to make future contractual obligations except for annual administrative fees of $207,500 owed to the Trustees pursuant to the Trust Agreement.

Item 7A.    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 Item 1 of this Form 10-K.

        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.

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Item 8.    Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Trustees and Unit Holders of
TEL Offshore Trust
Austin, Texas

        We have audited the accompanying statements of assets, liabilities and trust corpus—modified cash basis of TEL Offshore Trust (the "Trust") as of December 31, 2011 and 2010, and the related statements of distributable income and changes in trust corpus—modified cash basis for each of the three years ended December 31, 2011. These financial statements are the responsibility of the Corporate Trustee. Our responsibility is to express an opinion on the financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by the trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        As described in Note 3 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a basis of accounting other than accounting principles generally accepted in the United States of America.

        In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of TEL Offshore Trust as of December 31, 2011 and 2010, and its distributable income and changes in trust corpus for each of the three years ended December 31, 2011, on the basis of accounting described in Note 3 to the financial statements.

        The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. As discussed in Note 4 to the financial statements, the Trust has not received any royalties or paid distributions since 2009, which raises substantial doubt about its ability to continue as a going concern. The Trustees' plans concerning these matters are also discussed in Note 6 to the financial statements. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Deloitte & Touche LLP

Austin, Texas
March 30, 2012

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TEL OFFSHORE TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

STATEMENTS OF DISTRIBUTABLE INCOME

STATEMENTS OF CHANGES IN TRUST CORPUS

   

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

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NOTES TO FINANCIAL STATEMENTS

(1) Trust Organization and Provisions

        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 in liquidation and cancellation of Tenneco Offshore's common stock.

        On January 14, 1983, Tenneco Offshore distributed units of beneficial interest ("Units") in the Trust 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 December 31, 2011, the reserve amount was $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 has been increased by Chevron to $18.7 million in March 2012, approximately $18.1 million of which had been incurred through January 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 2.

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NOTES TO FINANCIAL STATEMENTS (Continued)

(1) Trust Organization and Provisions (Continued)

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

(2) Net Overriding Royalty Interest

        On October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale of 20% of the Royalty. The sale generated $1,600,000 in gross proceeds and occurred as part of a formal auction process for the Royalty. The Trust received from the Partnership a distribution of approximately $1,485,851, representing 99.99% of the net proceeds from the sale of $1,486,000. The Trust 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%, 100% and 98% of crude oil revenues from the Royalty Properties

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NOTES TO FINANCIAL STATEMENTS (Continued)

(2) Net Overriding Royalty Interest (Continued)

during 2011, 2010 and 2009, respectively. Sales to Chevron Corporation accounted for 100% of total gas revenues from the Royalty Properties during 2011, 2010 and 2009.

        The Trust's share of Royalty income was reduced by approximately $305,000, $293,010 and $320,329 in 2011, 2010 and 2009, respectively, for management fees paid to the Working Interest Owners as reimbursement for expenses incurred by them on behalf of the Trust. Such management fees were calculated as 3% of the Trust's share of the sum of revenues, production expenses and capital expenditures attributable to the Royalty Properties in each of the three years above.

(3) Basis of Accounting and Going Concern

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

        Modified Cash Basis of Accounting—The 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 (c);



(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 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

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NOTES TO FINANCIAL STATEMENTS (Continued)

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

from the Working Interest Owners. The financial statements of the Trust differ from 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.

        Oil and Gas Reserves.    The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices and production costs, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from estimates.

        The standardized measure of discounted future net cash flows is prepared using assumptions made pursuant to FASB and SEC guidelines. Such assumptions include using average fiscal-year oil and gas prices(calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month reporting period) and year-end costs for estimated future production expenditures. Discounted future net cash flows are calculated using a 10% discount rate. Changes in any of these assumptions could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.

        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 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

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NOTES TO FINANCIAL STATEMENTS (Continued)

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

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.

        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 Trustee. The changes in reserve 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 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 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 year ended December 31, 2011 applicable to the Trust or its financial statements.

        Going Concern.    The accompanying 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 4^th 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 financial statements do not include any adjustments that might result from the outcome of this uncertainty.

(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.

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(4) Distributions to Unit Holders (Continued)

        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 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 $15 million 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 $16.5 million to approximately $18.7 million, approximately $18.1 million of which had been incurred through January 31, 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 Islands 339. If development and production costs of the Royalty Properties exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net Proceeds since December 2008. As of October 31, 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 applicable to the Trust as of December 31, 2011). As of December 31, 2010, aggregate development and production costs for the Royalty Properties since November 2008 exceeded the related proceeds of production from the Royalty Properties by approximately $3.5 million. 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

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NOTES TO FINANCIAL STATEMENTS (Continued)

(4) Distributions to Unit Holders (Continued)

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 2011, the Trust had undistributed net loss of $2,162,703, representing the Trust's portion of the aggregate undistributed net loss of $10,813,516 associated with the Royalty Properties for 2011. For 2010, the Trust had undistributed net loss of $1,537,061. Undistributed net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. Undistributed net income represents positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners.

(5) Special Cost Escrow Account

        The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on certain factors, including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account, approximately $1,579, $7,946 and $7,923, for 2011, 2010 and 2009, respectively, serves to reduce the Trust's share of allocated production costs. As of December 31, 2011, 2010 and 2009, approximately $1,000, $1,000 and $4,306,275, respectively, 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.

        In 2011, there were no funds released from or deposited into the Special Cost Escrow account. 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, 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

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NOTES TO FINANCIAL STATEMENTS (Continued)

(5) Special Cost Escrow Account (Continued)

Cost Escrow account would be required in future periods in accordance with the underlying conveyance of the royalty if, and when, net proceeds would otherwise be payable on the royalty. In 2009, there were no funds released from or deposited into the Special Cost Escrow account.

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

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

        Deposits to the Special Cost Escrow Account will be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made.

(6) Reserve For Future Trust Expenses

        The Trust generally maintains a cash reserve, equal to approximately three times the average annual expenses of the Trust during each of the then past three years, to provide for future administrative expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the Trust has not received sufficient Net Proceeds to maintain the reserve at such level. During 2011, the Trust decreased its reserve (which then included $1,485,851 distributed by the Partnership resulting from the sale of 20% of the Royalty) by $894,113, to pay current expenses, resulting in a reserve balance of $944,917 as of December 31, 2011, or approximately 102% of the average annual expenses of the Trust during the three-year period ended December 31, 2011. During 2010, the Trust decreased its reserve by $911,064, to pay current expenses, resulting in a reserve balance of $352,017 as of December 31, 2010, or approximately 39% of the average annual expenses of the Trust during the three-year period ended December 31, 2010.

        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.

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(6) Reserve For Future Trust Expenses (Continued)

        On March 11, 2011, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell such portion, and only such portion, of the Royalty that will provide the Trust with a current distribution equal to $2,000,000 from the proceeds of such sale. 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 the sale of $1,486,000. The Trust will use such net proceeds solely for the payment of expenses of the Trust.

(7) Federal Income Tax Matters

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

(8) Commitments and Contingencies

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

(9) Supplemental Reserve Information (Unaudited)

        Estimates of the proved oil and gas reserves attributable to the Partnership's royalty interest are based on a reserve study prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants. The reserve study prepared by DeGolyer and MacNaughton as of October 31, 2011 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 then-estimated total plugging and abandonment costs related to Eugene Island 339, with costs to the Royalty relating thereto estimated to be approximately $17.6 million, approximately $16.5 million of which had been incurred, 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. 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 $18.1 of which had been incurred through January 2012, and without giving credit for an expected

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NOTES TO FINANCIAL STATEMENTS (Continued)

(9) Supplemental Reserve Information (Unaudited) (Continued)

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. Estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board. Accordingly, the estimates are based on existing economic and operating conditions in effect at October 31, 2011, with no provision for future increases or decreases except for periodic price redeterminations in accordance with existing gas contracts.

        Estimated net proved reserves attributable to the net profits interest owned by the Partnership, as of October 31, 2011, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):

        The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive Activities—Oil and Gas.Future cash inflows as of October 31, 2011,2010 and 2009 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended October 31, 2011, 2010 and 2009) to estimated future production.Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(9) Supplemental Reserve Information (Unaudited) (Continued)

gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions.

        The standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the Trust is as follows (dollars in thousands):

        The changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the Trust are as follows (dollars in thousands):

        Future cash inflows included in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves incorporate unweighted arithmetic average sales prices (inclusive of adjustments for quality and location) in effect at October 31, 2011, 2010 and 2009 as follows:

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(9) Supplemental Reserve Information (Unaudited) (Continued)

        On October 7, 2008, the Trust announced that production from the two most significant oil and gas properties associated with the Trust had ceased following damage inflicted by Hurricane Ike in September 2008. The platforms and wells on Eugene Island 339 were completely destroyed by the hurricane. Chevron has informed the Corporate Trustee that Chevron presently intends to pursue the redevelopment of the platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the Bureau of Ocean Energy Management ("BOEM") in response to Chevron's submission to the BOEM of a program to restore production at Eugene Island 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 in the fourth quarter of 2012. Restoration of production at Eugene Island 338 and 339 is a complex process, requires various governmental permits, and cannot be assured at this time. 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. 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. The costs for the redevelopment plan would be significant. Chevron and the Trust will bear the proportionately reduced post-redevelopment costs incurred for each Eugene Island 339 Royalty Property. 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. While Chevron has stated that it intends to redevelop Eugene Island 338 and 339, there is no obligation for Chevron to continue to pursue such redevelopment. Additionally, the Trust cannot predict at this time the further impact that 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. Based on the reserve study of DeGolyer and MacNaughton for the oil and gas reserves attributable to the Partnership as of October 31, 2007, 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.

        The reserve volumes and revenue values attributable to the Partnership's royalty interest were estimated from projections of reserves and revenue attributable to the combined interests consisting of

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(9) Supplemental Reserve Information (Unaudited) (Continued)

the Partnership's royalty interest and the retained interest of the Working Interest Owners in the Royalty Properties. Net reserves attributable to the Partnership's royalty interest were estimated by allocating to the Partnership a portion of the estimated combined net reserves of the subject properties based on the ratio of the Partnership's interest in future net revenues to combined future gross revenues. Because the net reserve volumes attributable to the Partnership's royalty interest are estimated using an allocation of reserves based on estimates of future revenue, a change in prices or costs will result in changes in the estimated net reserves. Therefore, the estimated net reserves attributable to the Partnership's royalty interest will vary if different future price and cost assumptions are used. All reserves attributable to the Partnership's royalty interest are located in the United States. Total future net revenues attributable to the Partnership's interest in the Royalty were estimated at $11.5 million as of October 31, 2011 based on the reserve study of DeGolyer and MacNaughton.

        The Partnership's share of gas sales can be recorded by the Working Interest Owner on the cash method of accounting or based on actual production. When revenues are reported based on actual production, there is no gas imbalance created. Under the cash method, revenues are recorded based on actual gas volumes sold, which could be more or less than the volumes the Working Interest Owners are entitled to based on their ownership interests. The Partnership's Royalty income for a period reflects the actual gas sold during the period.

(10) Related Party Transactions

        Each of the Working Interest Owners owns interests, for its own account, in leases that are in the same area as leases in which the Partnership has acquired or may acquire an interest. Such relationships may give rise to potential conflicts of interests in, among other things, the operation of such leases and in the acquisition and operation of any drainage leases acquired by a Working Interest Owner for its own account. Additionally, the Working Interest Owners and their affiliates are not prohibited from purchasing oil and gas produced from or attributable to any leases in which the Partnership has an interest.

        Crude oil sales to Chevron Corporation approximately 100%, 100% and 98% of crude oil revenues from the Royalty Properties during 2011, 2010 and 2009, respectively. During the year ended December 31, 2011, 2010 and 2009, 100% of Chevron's natural gas and natural gas liquids relative to the Trust's Royalty Properties were committed and sold to Chevron Natural Gas at spot market prices.

        The Trust's share of Royalty income was reduced by approximately $305,000, $293,000 and $320,000 in 2011, 2010 and 2009, respectively, for management fees paid to the Working Interest Owners as reimbursement for expenses incurred by them on behalf of the Trust. The aggregate amount of management fees paid to the Working Interest Owners was calculated as 3% of the Trust's share of the sum of revenues, production expenses and capital expenditures attributable to the Royalty Properties in 2011, 2010 and 2009.

(11) Subsequent Events

        On March 30, 2012, the Trust issued a press release announcing that there would be no trust distribution for the first quarter of 2012 for unitholders of record on March 30, 2012.

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(12) Selected Quarterly Financial Data (Unaudited)

        Summarized quarterly financial data is as follows:

        See Note 4 for a discussion regarding uncertainty of distributions.

*****

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Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

        None.

Item 9A.    Controls and Procedures.

Evaluation of disclosure controls and procedures.

        The Corporate Trustee maintains disclosure controls and procedures designed to ensure that information 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 Bank of New York Mellon Trust Company, N.A., as 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" included in this Form 10-K and "Trustee's Discussion and Analysis of Financial Condition and Results of Operation" included in this Form 10-K, for a description of certain risks relating to these arrangements and reliance 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 quarter ended December 31, 2011, 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 relating to the Trust. 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 Chevron.

Corporate Trustee's Annual Report on Internal Control over Financial Reporting

        A registrant's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting. A registrant's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified

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cash basis of accounting, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrants assets that could have a material effect on the financial statements.

        The Corporate Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Corporate Trustee conducted an evaluation of the effectiveness of the Trust's internal control over financial reporting based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Corporate Trustee's evaluation under the framework in Internal Control—Integrated Framework, the Corporate Trustee concluded that the Trust's internal control over financial reporting was effective as of December 31, 2011.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Item 9B.    Other Information.

        None.

PART III

Item 10.    Directors, Executive Officers and Corporate Governance.

        There are no directors or executive officers of the Registrant. The Trustees consist of a Corporate Trustee and three Individual Trustees. The Bank of New York Mellon Trust Company, N.A. serves as the Corporate Trustee, and Gary C. Evans, Thomas H. Owen, Jr. and Jeffrey S. Swanson serve as the three Individual Trustees. Any Trustee may be removed by the affirmative vote of two Individual Trustees or by the affirmative vote of a majority of the Units at a meeting of Unit holders of beneficial interest in the Trust at which a quorum is present.

        The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Corporate Trustee must comply with the bank's code of ethics.

        The Trust does not have a board of directors, and therefore does not have an audit committee, an audit committee financial expert, a compensation committee or a nominating committee.

Section 16(a) Beneficial Ownership Reporting Compliance.

        The Trust has no directors or officers. Accordingly, only holders of more than 10% of the Trust's Units are required to file with the SEC initial reports of ownership of Units and reports of changes in such ownership pursuant to Section 16 under the Securities Exchange Act of 1934. Based solely on a review of these reports, the Trust believes that the applicable reporting requirements of Section 16(a) of the Securities Exchange Act of 1934 were complied with for all transactions that occurred in 2011.

Item 11.    Executive Compensation.

        During the year ended December 31, 2011, the Corporate Trustee received compensation from the Trust in an aggregate amount of $229,478. During the year ended December 31, 2011, each of the Individual Trustees received compensation from the Trust in an aggregate amount of $76,209. The Trust does not have any executive officers.

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Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

(a)    Security Ownership of Certain Beneficial Owners.

        The Trust has no officers or directors. Accordingly, only holders of more than 5% of the Trust's Units are required to file reports with the SEC on Schedule 13D or Schedule 13G and holders of 10% or more of the Trust's Units are required to file initial and other reports with the SEC pursuant to Section 16 of the Securities Exchange Act of 1934. Based solely on a review of reports, the Trust is not aware of such holders as of March 29, 2012.

(b)    Security Ownership of Management.

        Not applicable.

(c)    Changes in Control.

        The Trust knows of no arrangements, including the pledge of securities of the Trust, the operation of which may at a subsequent date result in a change in control of the Trust.

Item 13.    Certain Relationships and Related Transactions, and Director Independence.

        Each of the Working Interest Owners may own interests, for its own account, in leases that are in the same area as leases in which the Partnership has acquired or may acquire an interest. Such relationships may give rise to potential conflicts of interests in, among other things, the operation of such leases and in the acquisition and operation of any drainage leases acquired by a Working Interest Owner for its own account. Additionally, the Working Interest Owners and their affiliates are not prohibited from purchasing oil and gas produced from or attributable to any leases in which the Partnership has an interest.

        Crude oil sales to Chevron Corporation accounted for approximately 100%, 100% and 98% of crude oil revenues from the Royalty Properties during 2011, 2010 and 2009, respectively. During the years ended December 31, 2011, 2010 and 2009, 100% of Chevron's natural gas and natural gas liquids relative to the Trust's Royalty Properties were committed and sold to Chevron Natural Gas at spot market prices.

        The Trust's share of Royalty income was reduced by approximately $305,000, $293,000 and $320,000 in 2011, 2010 and 2009, respectively, for management fees paid to the Working Interest Owners as reimbursement for expenses incurred by them on behalf of the Trust. The aggregate amount of management fees paid to the Working Interest Owners was calculated as 3% of the Trust's share of the sum of revenues, production expenses and capital expenditures attributable to the Royalty Properties in 2011, 2010 and 2009. Chevron, as the Managing General Partner of the Partnership, was paid a management fee of $1,309,488 for 2011 by the Partnership.

Item 14.    Principal Accountant Fees and Services.

        The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustees. The Trustees have appointed Deloitte & Touche, LLP and its affiliates (collectively "Deloitte") as the independent registered public accounting firm to audit the trust's financial statements for the fiscal year ending December 31, 2012. During fiscal 2011, Deloitte served as the Trust's independent registered public accounting firm and also provided certain tax services.

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        The following table presents the aggregate fees billed to the Trust for the fiscal years ended December 31, 2011 and 2010 by Deloitte:

PART IV

Item 15.    Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements

        The following financial statements are set forth under Part II, Item 8 of this Annual Report on Form 10-K on the pages as indicated:

(a)(2) Schedules

        Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.

(a)(3) Exhibits

        (Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. The Bank of New York Mellon Trust Company, N.A. succeeded JPMorgan Chase Bank as Corporate Trustee. JPMorgan Chase Bank is successor by mergers to the original corporate trustee, Texas Commerce Bank National Association.)

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) 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 on this 30th day of March, 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. In signing the report above, neither the Corporate Trustee nor the Individual Trustees imply that they perform any such function or that such function exists pursuant to the terms of the Trust Agreement under which they serve.

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