PART I

Item 1. Business.

DESCRIPTION OF THE TRUST

General

The TEL Offshore Trust (“Trust”), created under the laws of the State of Texas, maintains its offices at the office of the Corporate Trustee, The Bank of New York Trust Company, N.A. (“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 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 Trust Company acquired substantially all of JPMorgan Chase’s corporate trust business. JPMorgan Chase Bank was formerly known as The Chase Manhattan Bank and is the successor by mergers to the original name of the corporate trustee, Texas Commerce Bank National Association. George Allman, Jr., Gary C. Evans and Jeffrey S. Swanson serve as individual trustees (“Individual Trustees”) of the Trust. 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 (“SEC”). Electronic filings by the Trust with the SEC are available free of charge through the SEC’s website at www.sec.gov.

The principal asset of the Trust consists of a 99.99% interest in the TEL Offshore Trust Partnership (“Partnership”). Chevron U.S.A., Inc. (“Chevron”) owns the remaining .01% interest in the Partnership. The Partnership owns an overriding royalty interest (“Royalty”), equivalent to a 25% net profits interest, in certain oil and gas properties (the “Royalty Properties”) located offshore Louisiana.

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 interests.

On November 18, 1988, Chevron acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco, including all 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 these 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 Texaco 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 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.

Effective January 1, 1998, Energy Resource Technology, Inc. (“ERT”) acquired the East Cameron 354 property from SONAT. As a result of this 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 this 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, a Delaware corporation, merged (the “Merger”) with and into Texaco Inc., a Delaware corporation (“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 (ChevronTexaco Corporation is referred to herein as “ChevronTexaco”). Accordingly, the properties referred to herein by Chevron and Texaco are each now controlled by subsidiaries of ChevronTexaco.

On May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371 to Chevron. Accordingly, pursuant to the Conveyance of the Royalty Properties, Net Proceeds will be calculated for the collective Royalty Properties owned by Chevron after this date.

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 this transaction, Anadarko replaced Amerada as the Working Interest Owner of East Cameron 354 effective July 1, 2003 and also assumed Amerada’s obligation under the Conveyance with respect to this property.

Effective October 1, 2004, Apache Corporation (“Apache”) acquired Anadarko’s interests in East Cameron 354 and assumed Anadarko’s obligation under the Conveyance with respect to this property.

All of the Royalty Properties continue to be subject to the Royalty, and it is anticipated that the Trust and Partnership, in general, will continue to operate as if the above-described sales of the Royalty Properties had not occurred.

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 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 and East Cameron 371 on and after May 1, 2002; Anadarko with respect to East Cameron 354 on and after July 1, 2003 until October 1, 2004, and Apache with respect to East Cameron 354 after October 1, 2004).

A total of 4,751,510 units of beneficial interest in the Trust (“Units”) are issued and outstanding. The Units have been traded on the Nasdaq SmallCap Market since August 31, 2001. Previously the Units were traded on the OTC Bulletin Board. The Units were also traded on pink sheets. From inception of the Trust to December 31, 2006, distributions to Unit holders totaled approximately $116,132,000 or approximately $24.44 per Unit. See Note 4 to the Notes to Financial Statements under Item 8 of this Form 10-K for a discussion regarding uncertainties of distributions.

The terms of the TEL Offshore Trust Agreement (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; (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 $38.3 million as of October 31, 2006 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 (the “Partnership Agreement”) provide that the Partnership shall dissolve upon the occurrence of any 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 shall be liable for all damages and costs to the Trust if it breaches this agreement.

Under the Conveyance and the Partnership Agreement, the Trust is entitled to its share (99.99%) of 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 its 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 shall 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 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 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 Royalty Properties are primarily operated by the Working Interest Owners although certain other parties operate some of 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 (“Offshore II”) 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 Property acquired by TEPI is West Cameron 643 and East Cameron 371. As a result of such acquisition, TEPI replaced Chevron as the Working Interest Owner of such property and assumed Chevron’s obligations under the Conveyance with respect to such property 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 Working Interest Owner of the East Cameron 354 property and also assumed SONAT’s obligations under the Conveyance with respect to such 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 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, a Delaware 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 by Chevron and Texaco are each now controlled by subsidiaries of ChevronTexaco. On May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371 to Chevron. Accordingly, pursuant to the Conveyance of the Royalty Properties,

net proceeds will be calculated for the collective Royalty Properties owned by Chevron after this date. 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 obligation 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.

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. For a discussion of the cash reserves being established by the Trust, see “Management’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 which 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 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.

Under current judicial decisions, the Federal Energy Regulatory Commission (“FERC”) is not considered to be empowered to compel 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 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.

Ownership of Units

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.

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. Unit holders who acquired Units after October 11, 1990, are entitled to percentage depletion on Royalty income attributable to those Units.

Backup Withholding

Distributions from the Trust are generally subject to backup withholding at a rate of 28% of these distributions. 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 Units exceeds one year at the time of sale or exchange. A long-term capital gains rate of 15% applies to most capital assets sold or exchanged with a holding period of more than one year. 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 on exchange.

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 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 income is subject to withholding at the highest applicable tax rate, 35% for individual non-U.S. Unit holders.

The Code and the Treasury Regulations thereunder treat the publicly traded Trust as if it were a United States real property holding corporation. Accordingly, non-U.S. Unit holders may be subject to United States federal income tax on any gain from the disposition of their Units.

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 adviser with respect to his 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. The Royalty 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 encouraged to consult their legal and tax advisers regarding the applicability of these considerations to their individual circumstances.

The Texas legislature passed H.B. 3, 79th Leg., 3d C.S. (2006), which was signed into law on May 18, 2006. H.B. 3 significantly reforms the Texas franchise tax system and replaces it with a new Texas margin tax system. The margin tax expands the type of entities subject to tax to generally include all active business entities, including corporations and limited liability companies currently subject to the franchise tax. The new margin tax also will apply to the following common entity types that are not currently subject to tax: general and limited partnerships (unless otherwise exempt), limited liability partnerships, trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stock companies, holding companies, and joint ventures. The effective date of the margin tax is January 1, 2008, but the tax generally will be imposed on gross revenues generated in 2007 and thereafter.

Trusts and partnerships that meet statutory requirements and receive at least 90% of their gross income from designated sources, including royalties from mineral properties, and do not receive more than 10% of their income from operating an active trade or business, are generally exempt from the Texas margin tax as “passive entities.” Although the income of the Trust consists primarily of royalty income from the sale of crude oil and natural gas, there is no clear authority that the Trust satisfies all the margin tax statutory requirements for the exemption for passive entities to apply. Therefore, prior to clarification by additional legislative action or the issuance of applicable administrative rules promulgated by the Texas Comptroller, it is uncertain whether the Trust would be exempt from the margin tax as a passive entity or subject to the margin tax at the trust level. The Corporate Trustee is continuing to evaluate the impact of H.B. 3 to the Trust.

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 $38.3 million as of October 31, 2006, based on the reserve study of DeGolyer and MacNaughton, independent petroleum engineers, discussed herein. Based on the DeGolyer and MacNaughton reserve study, as of October 31, 2006 in order to correspond with distributions to the Trust, it is estimated that approximately 72% of future net revenues from the Royalty Properties are expected to be received by the Trust during the next 3 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 DeGolyer and MacNaughton reserve study. 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. 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 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 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 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.

DESCRIPTION OF ROYALTY PROPERTIES

Producing Acreage and Wells

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

				Working				Gross Wells Drilled as of
			Current	Interest				October 31, 2006
	Acquisition		Working	Owner’s				Wells					Successful
	Date		Interest	Ownership			Gross	Drilled(1)					(2)(3)
Property	(Mo.-Yr.)		Owner	Interest(%)(4)			Acres	Expl.		Dev.			Oil		Gas
East Cameron 354(5)		12-72	Apache		11.14		5,000		2		4		0			5
West Cameron 643 unit		12-72	Chevron		35.86		5,000		3		17		0			14
Eugene Island 339 non-unit		12-72	Chevron		50.00		5,000		2		33	(6)	19	(6)		0
Eugene Island 339 5500’ unit		12-72	Chevron		42.05		5,000		0		5		5			0
Eugene Island 339 4500’ unit		12-72	Chevron		38.50 24.44	gas oil	5,000		0		20		16			0
Eugene Island 342 SW/4		12-72	Chevron		.06		5,000		4		5		0			7
Eugene Island 342 NW/4		12-72	Chevron		0.18		5,000		2		4		0			4
Eugene Island 348(7)		12-72	Devon		50.00		5,000		4		5		0			7
West Cameron 642		12-72	Chevron		25.00		5,000		4		7		0			8
East Cameron 370(8)		1-73	N.A.		25.00		5,000		3		1		0			4
East Cameron 371		1-73	Chevron		7.50		5,000		7		2		0			4
Vermilion 246 (11)		1-73	Chevron		33.37		5,000		3		3		0			4
West Cameron 41 E/2(9)		3-74	N.A		.30		2,500		0		0		0			0
Ship Shoal 183 N/2		7-88	Chevron		66.67		2,500		1		11		8			4
Ship Shoal 183 unit		7-88	Chevron		34.29		1,875		1		22		20			3
Ship Shoal 183 F-3		7-88	Chevron		100.0		5,000		1		0		0			1
Ship Shoal 183 F-1		7-88	Chevron		50.00		5,000		1		0		1			0
Eugene Island 208		8-73	Devon		100.00		1,250		0		3		0			3
Eugene Island 367(10)		3-74	N.A.		1.60		5,000		2		9		0			9
South Marsh Island 252		3-74	Chevron		3.00		4,997		2		0		0			1
South Timbalier 36		3-74	Chevron		.26		5,000		2		20		9			11
South Timbalier 37		3-74	Chevron		.26		5,000		13		41		39			3
							98,122		57		211		117			91

(1) As of October 31, 2006, there were 2 wells in the process of drilling. See “Operations” under Item 7 of this report for a discussion of drilling activity during 2006.

(2) As of October 31, 2006, there were 108 producing completions.

(3) Multiple completions are counted as one well. South Timbalier 37 has 5 multiple completion wells and Ship Shoal 182/183 has 2 multiple completion wells.

(4) These percentages represent the working interest owner’s interest subject to the Partnership’s net proceeds.

(5) Apache purchased this working interest from Anadarko effective October 1, 2004. This lease expired in 2005. Wells were plugged and abandoned in 2006. The platforms to which the wells were connected have not yet been abandoned; such abandonment is in process and is expected to be completed in the third quarter of 2007.

(6) Eugene Island 339 C-17 and C-18 wells are producing in this property but are not included here; they are not subject to the Partnership’s net proceeds until they pay out.

(7) This lease expired in 2004.

(8) This lease expired in 1996.

(9) This lease expired in November 2002, and all wells on the lease had been abandoned as of November 2003.

(10) This lease expired on May 30, 1996. It was leased again as OCS-G 19800 effective July 1, 1998. Neither Chevron nor any affiliates of ChevronTexaco have an interest in OCS-G-19800.

(11) This lease (Vermillion 246 Block, OCS-G 1147) was terminated in 2002. Abandonment work was completed mid 2005.

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, 2006. The following letter summarizes 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 Trust recognizes its royalty income. See Notes 2 and 9 in the Notes to Financial Statements under Item 8 of this Form 10-K.

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 letter represent estimates only and should not be construed as being exact. The discounted present values shown by the DeGolyer and MacNaughton letter 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. In accordance with applicable regulations of the SEC, estimated future net revenues were based, generally, on current prices and costs, whereas actual future prices and costs may be materially greater or less. In addition, 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.

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. Total future net revenues attributable to the Partnership’s interest in the Royalty were estimated at $38.3 million as of October 31, 2006 based on the reserve study of DeGolyer and MacNaughton. The Partnership’s Royalty income for a period reflects the actual gas sold during the period.

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 described in the foregoing letter. The quantities of reserves indicated by such formula will 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 letter 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 letter have not been reduced for future costs and expenses of the Trust, which are expected to approximate $600,000 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.

In addition, 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. These capital expenditures could have a significant effect on the actual future net revenues attributable to the Partnership’s interest in the Royalty.

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 Working Interest Owners have advised the Trust that there have been no events subsequent to October 31, 2006 that have caused a significant change in the estimated proved reserves referred to in the DeGolyer and MacNaughton letter.

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

During 2005, Hurricane Katrina and Hurricane Rita caused significant damage to various platforms and third-party transportation systems which resulted in oil and gas production delays in our Royalty Properties. During 2006 several of the platforms and facilities on the Royalty Properties were restored; however, certain projects remain to be completed during 2007 to increase production to pre-hurricane levels. The Trust may have to fund our share of project costs and other related expenditures that are not covered by insurance of the operator of the Royalty Properties. Further delays in repairs on third-party transportation systems may continue to limit production. Additionally, the extensive damage caused by these hurricanes has led to significant demand for services and supplies for repairs in the offshore Gulf of Mexico, which has increased current and future levels of expenditures. The reduced oil and gas production and increased costs reduced the cash income distributions to unitholders significantly during 2006 and may continue to affect cash income distributions during a portion or all of 2007. During the fourth quarter 2006, the Trust resumed distributions. The fourth quarter distribution of $1.7 million was paid on January 11, 2007. On March 30, 2007, the Trust announced its first quarter distribution of approximately $1.2 million.

DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244

February 9, 2007

Chevron U.S.A. Inc.
Chevron Place
935 Gravier Street
New Orleans, Louisiana 70012

Gentlemen:

Pursuant to your request, we have prepared estimates, as of October 31, 2006, of the extent and value of the proved crude oil, condensate, and natural gas reserves of a net profits interest owned by TEL Offshore Trust Partnership (the Trust Partnership). This net profits interest (the Trust Partnership Interest) is in certain offshore leases owned by Chevron U.S.A. Inc. (Chevron), as successor in title to Tenneco Oil Company (Tenneco), by Pennzoil Petroleum Company (Pennzoil), as successor in title to Chevron, and by Texaco Exploration and Production, Inc. (Texaco), as successor in title to Chevron. The interest appraised consists of a 25 percent net profits interest in 17 leases (the Subject Properties), which are located in the Gulf of Mexico offshore from Louisiana. Before acquisition by Chevron, the Subject Properties had been transferred to Tenneco upon the dissolution of Tenneco Exploration Ltd. (Exploration I), a limited partnership formerly consisting of Tenneco and Tenneco West Inc. Exploration I conveyed the net profits interest to the Trust Partnership, which is 99.99-percent owned by TEL Offshore Trust, by the Conveyance of Overriding Royalty Interests effective January 1, 1983. The Subject Properties were acquired by Chevron on November 18, 1988. Certain of the Subject Properties were subsequently acquired by Pennzoil effective July 1, 1992, and certain others were acquired by Texaco effective December 1, 1994. One of the Pennzoil Subject Properties was subsequently acquired by SONAT Exploration Company (SONAT) and certain other Pennzoil Subject Properties were acquired by Amoco Production Company (Amoco), both effective October 1, 1995. The SONAT property was subsequently acquired by Amerada Hess Corporation (Amerada Hess) effective January 1, 1998, which property was then acquired by Anadarko Petroleum Corporation (Anadarko) effective June 1, 2003, and subsequently acquired by Apache Corporation (Apache) effective October 1, 2004. Another of the Pennzoil Subject Properties was acquired by Devon Energy Production Co. (Devon) effective December 29, 1999, and then by Maritech Resources, Inc. (Maritech) effective January 1, 2005. Chevron Corporation, of which Chevron is a wholly owned subsidiary, and Texaco Inc., of which Texaco is a wholly owned subsidiary, merged on October 9, 2001. As a result of the merger, Texaco became a wholly owned subsidiary of Chevron Corporation. Subsequent to the merger, Texaco assigned the interests in its properties to Chevron. These companies mentioned herein are hereinafter referred to as the Owners. The Managing Partner of the Trust Partnership is Chevron.

Information used in the preparation of this report was obtained from the Owners. During this investigation, we consulted freely with the officers and employees of the Owners and were given access to such accounts, records, geological and engineering reports, and other data as were desired for examination. In the preparation of this report we have relied, without independent verification, upon information furnished by the Owners with respect to property interests owned by the Trust Partnership, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. It was not considered necessary to make a field examination of the physical condition and operation of the Subject Properties. Additionally, this

Our reserves estimates are based on a detailed study of the Subject Properties and were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, consideration of the stage of development of the reservoir, and the quality and completeness of basic data.

Reserves estimated herein are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from the Subject Properties after October 31, 2006. Combined net reserves are defined as those reserves remaining after deducting royalties and interests owned by others from gross reserves. Net reserves are defined as that portion of the combined net reserves attributable to the interests owned by the Trust Partnership. Gas volumes are expressed as sales-gas reserves at a temperature of 60 degrees Fahrenheit and at a legal pressure base of 14.73 pounds per square inch absolute. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Condensate reserves estimated herein are those to be obtained by normal separator recovery.

Petroleum reserves included in this report are classified as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs as of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved — Reserves that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. Commercial productivity has been established by actual production, successful testing, or in certain cases by favorable core analyses and electrical log interpretation when the producing characteristics of the formation are known from nearby fields. Volumetrically, the structure, areal extent, volume, and characteristics of the reservoir are well defined by a reasonable interpretation of adequate subsurface well control and by known continuity of hydrocarbon-saturated material above known fluid contacts, if any, or above the lowest known structural occurrence of hydrocarbons.

Developed — Reserves that are recoverable from existing wells with current operating methods and expenses.

Developed reserves include both producing and nonproducing reserves. Estimates of producing reserves assume recovery by existing wells producing from present completion intervals with normal operating methods and expenses. Developed nonproducing reserves are in reservoirs behind the casing or at minor depths below the producing zone and are considered proved by production from other wells in the field, by successful drill-stem tests, or by core analyses from the particular zones. Nonproducing reserves require only moderate expense to be brought into production.

Undeveloped — Reserves that are recoverable from additional wells yet to be drilled.

Undeveloped reserves are those considered proved for production by reasonable geological interpretation of adequate subsurface control in reservoirs that are producing or proved by other wells but are not recoverable from existing wells. This classification of reserves requires drilling of additional wells, major deepening of existing wells, or installation of enhanced recovery or other facilities.

All of the proved reserves estimated herein are classified as proved developed. There are no proved undeveloped reserves for the properties evaluated in this report.

The properties evaluated consist of 17 leases located offshore from Louisiana. These 17 leases include 9 productive properties (including 2 leases covering separate portions of the south half of Ship Shoal Block 183) and 8 leases to which no reserves have been assigned. Maritech, Pennzoil, Apache, and Amoco own an interest in one property each, none of which are productive. Chevron owns an interest in the remaining 13 properties, including 4 to which no reserves have been assigned.

The reserves volumes and revenue values shown in this report were estimated from projections of reserves and revenue attributable to the “Combined Interests,” defined herein as the Trust Partnership Interests and the interests retained in the Subject Properties by Chevron, Pennzoil, Apache, Amoco, or Maritech. Net reserves attributable to the Trust Partnership Interests were estimated by allocating to the Trust Partnership a portion of the estimated combined net reserves of the Subject Properties based on future revenue. The formula used to estimate the net reserves attributable to the Trust Partnership Interest is as follows:

Trust Partnership Interest net reserves =	Trust Partnership Interest future net revenue	´ Combined net reserves
	Combined future gross revenue

This formula was applied separately to the Pennzoil, Apache, Amoco, and Maritech groups of properties and then to the Chevron (remaining properties) group; the results were then added together to obtain the total reserves for the Trust Partnership Interest. Because the net reserves volumes attributable to the Trust Partnership 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 Trust Partnership Interest will vary if different future price and cost assumptions are used. Trust Partnership Interest net revenue and net reserves estimates included in this report have been estimated from reserves and revenue attributable to the Combined Interests using procedures and calculation methods as specified by Chevron and represented by Chevron to be in accordance with the Conveyance of Overriding Royalty Interests.

Units have been formed for several common reservoirs that underlie the Subject Properties and adjacent leases. In those cases, the estimated gross reserves of the entire reservoir are shown and the resulting combined Trust Partnership and Chevron, Pennzoil, Apache, Amoco, or Maritech interests in the reservoir unit are used to estimate these Combined Interests net reserves.

Data available from wells drilled on the appraised properties through October 2006 were used in estimating gross ultimate recovery. Gross production through October 31, 2006, was deducted from the gross ultimate recovery to arrive at estimates of gross reserves.

Estimated net proved reserves attributable to the Trust Partnership Interest, as of October 31, 2006, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):

	Oil and Condensate (bbl)			Natural Gas (Mcf)
Proved Developed Reserves
Reserves as of October 31, 2005		407,804		1,940,162
Revisions of Previous Estimates		74,145		116,431
Improved Recovery		0		0
Purchases of Minerals in Place		0		0
Extensions, Discoveries, and Other Additions		7		614,862
Production1		(91,587	)	(438,332	)
Sales of Minerals in Place		0		0
Reserves as of October 31, 2006		390,369		2,233,123

1 Production was estimated based on the ratio as of October 31, 2005, of the Trust Partnership Interest net reserves to the Combined Interests net reserves. This ratio was then applied to the production net to the Combined Interests for the period from November 1, 2005, through October 31, 2006.

Revenue values in this report are expressed in terms of estimated combined future net revenue, future net revenue attributable to the Trust Partnership Interest, and present worth of these future net revenues. Future gross revenue is that revenue which will accrue from the production and sale of the estimated combined net reserves. Combined future net revenue values were calculated by deducting operating expenses and capital costs from the future gross revenue of the Combined Interests. These monthly values for the aggregate of the Combined Interests in the Subject Properties 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 2007. The future accrual or escrow amounts for each of the five groups of properties were deducted from the combined future net revenue at the end of each quarter, as specified by Chevron. Interest on the balance of the accrued capital and abandonment costs at the rate of 2.47 percent per year as specified by Chevron was credited monthly. The adjusted revenue resulting from subtracting the overhead charge and accrued capital and abandonment costs was multiplied by a factor of 25 percent to arrive at the future net revenue attributable to the Trust Partnership Interest. The above calculations were made monthly for each of the five groups of the properties (Chevron, Pennzoil, Apache, Amoco, and Maritech). Interest was charged monthly on the net profits deficit balances (costs not recovered currently) at the rate of 2.47 percent per year as specified by Chevron. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization; in this report, present worth values using a discount rate of 10 percent are reported. Future income tax expenses were not taken into account in estimating future net revenue and present worth. No deductions were made in the foregoing reserves estimates for any outstanding production payments.

Revenue values in this report were estimated using the initial prices and costs provided by Chevron. Future prices were estimated using guidelines established by the United States Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB). These guidelines require the use of prices for oil and condensate in effect on October 31, 2006. The following assumptions were used for estimating future prices and costs:

Oil and Condensate Prices

Oil and condensate prices were furnished by Chevron and were the prices in effect on October 31, 2006. These prices were used as initial prices with no increases based on inflation.

Natural Gas Prices

Initial gas prices furnished by Chevron were prices in effect on October 31, 2006. These initial prices were held constant for the life of the properties.

Operating Expenses and Capital Costs

Current estimates of operating expenses were used for the life of the properties with no increases in the future based on inflation. Future capital expenditures were estimated using 2006 values and were not adjusted for inflation. Abandonment costs have been estimated as capital costs for all properties, including the eight leases which are considered depleted and to which no reserves have been assigned.

A summary of estimated revenue and costs attributable to the Combined Interests in proved reserves of the Subject Properties and the future net revenue and present worth attributable to the Trust Partnership Interest, as of October 31, 2006, is as follows:

	Properties
	Chevron		Pennzoil		Apache		Amoco		Maritech		Total
Combined Interests
Future Gross Revenue ($)	184,720,911			0	0			0	0		184,720,911
Operating Expenses ($)	(28,799,297	)		0	0				0		(28,799,297	)
Capital Costs ($)1	(24,160,550	)		0	(457,706	)		0	(379,250	)	(24,997,506	)
Future Net Revenue ($)	131,761,064			0	(457,706	)		0	(379,250	)	130,924,108
Cost Escrow as of 10-31-06 ($)	26,634,236			0	475,352			0	475,352		27,584,940
Interest Credit on Accrued Balance ($)	2,025,945			0	5,868			0	0		2,031,813
Interest on Deficit ($)	(72	)		0	0			0	0		(72	)
Overhead ($)	(7,191,039	)		0	(13,905	)		0	(11,377	)	(7,216,321	)
Revenue Subject to Net Profits Interest ($)	153,230,134			0	9,609			0	84,725		153,324,468
Trust Partnership Interest
Future Net Revenue ($)2	38,307,500			0	2,400			0	21,181		38,331,081
Present Worth at 10 Percent ($)2	30,784,021			0	2,303			0	21,006		30,807,330

1 Includes abandonment costs.

2 Future income tax expenses were not taken into account in the preparation of these estimates.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 10–13, 15 and 30(a)–(b) of Statement of Financial Accounting Standards No. 69 (November 1982) of the FASB and Rules 4–10(a) (1)–(13) of Regulation S–X and Rule 302(b) of Regulation S–K of the SEC; provided, however, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of this report, we are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor. In our opinion, we have made the investigations necessary to enable us to estimate the petroleum reserves reported herein. Estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information

become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

	Submitted,

	DeGOLYER and MacNAUGHTON

	Paul J. Szatkowski, P.E.
	Senior Vice President
	DeGolyer and MacNaughton

MARKETING

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

It should be noted that substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major petroleum producing nations, as well as the regional supply and demand for gas, weather, industrial growth, conservation measures, competition and other variables. See Note 4 to the Notes to Financial Statements under Item 8 of this Form 10K for a discussion regarding uncertainty of distributions.

Gas Marketing

During the years ended December 31, 2004, 2005 and 2006, all 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.

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 Trust 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 Trust 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.

The following paragraphs discuss the marketing of gas from the principal Royalty Properties.

West Cameron 643. West Cameron 643 contributed approximately 1% of the revenues from natural gas sales from the Royalty Properties in 2006. The average price received for natural gas from all of the Working Interest Owner’s purchasers on West Cameron 643 during 2006 was $5.07 per Mcf.

East Cameron 371. East Cameron 371 contributed less than 1% of the revenues from natural gas sales from the Royalty Properties in 2006. The average price received for natural gas from all of the Working Interest Owner’s purchasers on East Cameron 371 during 2006 was $6.75 per Mcf.

Ship Shoal 182/183. Ship Shoal 182/183 contributed approximately 81% of the revenues from gas sales from the Royalty Properties in 2006. The average price received for natural gas from all of the Working Interest Owner’s purchasers on Ship Shoal 182/183 during 2006 was $6.71 per Mcf.

Eugene Island 339. Eugene Island 339 contributed approximately 15% of the revenues from natural gas sales from the Royalty Properties in 2006. The average price received for natural gas from all of the Working Interest Owner’s purchasers on Eugene Island 339 during 2006 was $6.59 per Mcf.

Oil Marketing

Crude oil purchases by ChevronTexaco accounted for approximately 99% of total crude oil revenues from the Royalty Properties during 2004, 2005 and 2006.

The Supply and Distribution Department of Chevron currently purchases crude oil at prices based on its own published pricing bulletins with an adjustment for gravity and transportation charges. Average monthly prices for fiscal year 2006 ranged from $56.39 per barrel to $67.20 per barrel.

COMPETITION AND REGULATION

Competition

The Working Interest Owners experience competition from other oil and gas companies in all phases of its operations. Numerous companies participate in the exploration for and production of oil and gas. The Working Interest Owners have 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”).

The operations of the Working Interest Owners under federal oil and gas leases offshore the United States are subject to regulations of the United States Department of Interior which currently impose absolute liability upon lessees for the cost of cleanup of pollution resulting from their operations.

FERC Regulation

In general, the FERC regulates the tansportation of natural gas in interstate commerce by interstate pipelines. Over the course of approximately the previous decade, the FERC 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 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 detennine whether further changes are needed. As to these various developments, the working interest owners have advised the Trust 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.

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.

Natural gas pipeline facilities used for the transportation of natural gas in interstate commerce are subject to Federal minimum safety requirements. These requirements, however, are not applicable to, inter alia: (1) onshore gathering facilities outside: (i) the limits of any incorporated or unincorporated city,

town, or village; and (ii) any designated residential or commercial area; or (2) pipeline facilities on the Outer Continental Shelf (“OCS”) upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator. See 49 C.F.R. § 192.1(b). The Corporate Trustee has been informed that the Royalty Properties are located in Federal waters on the OCS. The standards governing pipeline safety have undergone recent changes and it is possible that future changes in the regulations and statutes may occur which may increase the stringency of the standards or expand the applicability of the standards to facilities not currently covered.

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 Working Interest Owners have advised the Trust that they 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.

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 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 Working Interest Owners are currently maintaining their required OSFR. Although the Working Interest Owners have advised the Trust that current environmental regulation has had no material adverse effect on the Working Interest Owners’ present method of operations, future environmental regulatory developments such as stricter environmental regulation and enforcement policies cannot presently be quantified.

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 Working Interest Owners have advised the Trust that these costs have not had a material adverse impact on their operations.

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

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 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 which 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, 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. In the event of a serious incident of pollution, the Department of the Interior may require a lessee under federal leases to suspend or cease operations in the affected areas.

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.

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.

The Trust’s quarterly distributions are highly dependent upon the prices realized from the sale of natural gas and oil, and a material decrease in such prices could reduce the amount of Trust distributions. 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 Iraq;

· worldwide economic conditions;

· weather conditions;

· the supply and price of foreign 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.

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. A significant percentage of the natural gas and natural gas liquids produced from the Royalty Properties is currently being sold to various third party purchasers under a mix of term and spot agreements by ChevronTexaco Natural Gas. A majority of crude oil produced by the Royalty Properties is being sold to subsidiaries of ChevronTexaco based on pricing bulletins.

Increased production and development costs for the Royalty will result in decreased 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.

During 2005, Hurricane Katrina and Hurricane Rita caused significant damage to various platforms and third-party transportation systems. The extensive damage caused by these hurricanes has led to significant demand for services and supplies for repairs in the offshore Gulf of Mexico. These incurred costs have reduced and may continue to reduce Royalty income.

If development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties, the Trust will not receive net proceeds for those properties until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.

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.

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 underlying 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 natural gas reserves. Ultimately, actual production, revenues and expenditures for the underlying 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 and the independent reserve engineer engaged by the Trust. While the Trustees have no reason to believe the reserve estimates included in this report are not accurate, to the extent additional information exists that could affect their reserve estimates, the estimated reserves in these reports could also be too low.

Operating risks for the Working Interest Owners’ interests in the Royalty Properties can adversely affect 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 other natural disasters at any of the Royalty Properties will reduce Trust distributions by the amount of uninsured costs. Offshore activities are also subject to a variety of additional operating risks, such as hurricanes and other weather disturbances. These accidents may result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any uninsured costs would be deducted as a production cost in calculating net proceeds payable to the Trust.

As described in this report, Hurricanes Katrina and Rita caused significant damage during 2005. Most platforms and facilities on the Royalty Properties were restored during 2006, however, certain projects remain to be completed during 2007 to increase production to pre-hurricane levels. Further, delays in repairs on third-party transportation systems may continue to limit production and Royalty income from the Royalty Properties.

Terrorism and continued 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, the war in Iraq 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.

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.

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.

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 interests owners and managing general partner for information regarding the Royalty Properties.

The Trustees rely on the working interest owners and managing general partner 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 report, (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 relies 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 does 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 relies, 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 to 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 Property 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.

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. We cannot assure you that any such sale will be on terms acceptable to all Unit holders. For a more complete description of these matters, see “—Termination of the Trust” under Item 1 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. Additionaly, 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 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, 2006.

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.

Item 4. Submission of Matters to a Vote of Security Holders.

There were no matters submitted to a vote of security holders during the fourth quarter of 2006.

PART II

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

The Trust Units are traded on the Nasdaq SmallCap Market under the symbol “TELOZ”. At March 30, 2007, the 4,751,510 Units outstanding were held by 2,393 Unit Holders of record. The high and low sales price as reported by the Nasdaq SmallCap Market, and distributions for each quarter for the years ended December 31, 2006 and 2005, were as follows:

Quarter	High		Low		Distribution
2006:
Fourth	$	10.69	$	5.58		$	.357301
Third	8.10		5.35			.000000
Second	9.91		5.21			.000000
First	12.00		8.35			.000000
2005:
Fourth	$	11.85	$	9.10		$	.381145
Third	13.92		9.65			1.146507
Second	10.75		6.38			.350315
First	17.49		7.59			.066597

See 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.

	Year Ended December 31,
	2006		2005		2004		2003		2002
Royalty income	$	2,510,936	$	9,854,531	$	5,987,936	$	4,174,682	$	2,166,927
Distributable income	$	1,697,721	$	9,239,617	$	5,344,207	$	3,634,388	$	1,342,411
Distributions per Unit	$	0.357301	$	1.944564	$	1.124739	$	0.764891	$	0.282523
Total assets	$	3,375,093	$	3,239,290	$	3,901,263	$	2,107,166	$	1,945,413

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Critical Accounting Policies

The financial statements of the Trust are prepared on the following basis:

(a) Royalty income 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); and

(b) Trust general and administrative expenses are recorded when paid, except for the cash reserved for future general and administrative expenses.

(c) 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.

This manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the Working Interest Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles, Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.

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

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. Reference is made to Note 9 in the Notes to Financial Statements under Item 8 of this Form 10-K, which contains certain unaudited supplemental reserve information, for an estimate of future Royalty income attributable to the Partnership, of which the Trust has a 99.99% interest.

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

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

The calculated reserve amount at December 31, 2005 and 2006 was $1,364,203 and $1,623,886, respectively. During the first, second and third quarters of 2006, the Trust used $164,390, $188,829 and $133,181, respectively, from the Trust’s cash reserve account to pay the Trust’s general and administrative expenses when insufficient Royalty income was received by the Trust. These amounts were withheld from the calculation of fourth quarter distributable income to increase the reserve to its calculated amount.

Based upon the significantly reduced oil and gas production during the second half of 2005, due to hurricane-related damages in the areas where the Royalty Properties are located, the current and future expected deficit for expenditures subject to recovery from future royalty income, estimated future capital expenditure projects for repairs or tie-backs to alternative pipelines, and additional potential future exploratory activities being considered by Working Interest Owners, the cash income distributions to Unit holders decreased significantly during 2006 and may continue to be affected during a portion or all of 2007.

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 and by the applicable Working Interest Owners. The Trustees have no control over these operations or internal controls relating to this information.

At the end of October 2005, approximately half of Chevron oil-equivalent production in the Gulf of Mexico remained shut in due to damages from hurricanes in the third quarter. The time it will take to resume this production is uncertain, and some of the volumes may not be sufficiently economic to restore. As of December 31, 2006, Eugene Island 339 gas sales have not resumed, but production is currently expected to resume during the third quarter of 2007 after a new sales point is built by the operator to replace the Eugene Island 338 sales point destroyed by Hurricane Rita. The operator of the pipeline has advised that the hurricane-related damages on the pipeline were extensive and repair work has been suspended indefinitely. The Working Interest Owner for Eugene Island 339 has advised the Trustee that the Working Interest Owner plans to extend the existing line within the field and connect to an existing sales point on Eugene Island 361. The Working Interest Owner has also advised the Trust that the Working Interest Owner has completed the project to compress and re-inject gas to the B-5 well, which allows the operator to increase oil production and to limit flaring of gas. Eugene Island 339 oil production increased during the third quarter of 2006 and increased further during the fourth quarter of 2006 as the B-5 well gas injection project was completed. On Ship Shoal 182/183, gas production and sales resumed in July 2006 and full production resumed in the fourth quarter of 2006. On West Cameron 643, production was shut in from September 2005 following Hurricane Rita’s major damage to various platforms, but limited gas production resumed in late July 2006 before the wells loaded up and additional repairs were required.

Years 2006 and 2005

Royalty income decreased approximately 75% from $9,854,531 in 2005 to $2,510,936 in 2006 primarily due to a decrease in gas revenues and crude oil and condensate revenues as discussed below.

For 2006, the Trust had undistributed net income of $2,092. For 2005, the Trust had no undistributed net income or loss. Undistributed net income represents positive Net Proceeds generated during the period that were applied to an existing loss carryforward. Undistributed net loss represents negative Net Proceeds generated during the respective period. An undistributed net loss is carried forward and offset, in future periods, by positive Net Proceeds earned by the related Working Interest Owner(s).

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 75% from $16,337,625 in 2005 to $4,003,561 in 2006, primarily due to a 63% decrease in natural gas and gas products volumes from 2,287,314 Mcf equivalents in 2005 to 600,477 Mcf equivalents in 2006. The average price receieved for natural gas decreased 9% from $7.31 per Mcf in 2005 to $6.70 Mcf in 2006.

Crude Oil and Condensate

Crude oil and condensate revenues decreased 16% from $32,051,988 in 2005 to $26,869,007 in 2006, due primarily to a 35% decrease in crude oil and condensate volumes from 650,466 barrels in 2005 to 421,763 barrels in 2006. This decrease was partially offset by the increase in average crude oil and condensate prices by 30% from $49.28 in 2005 to $63.71 in 2006.

Operating and Capital Expenditures

Operating expenses paid by the Working Interest Owners increased 38% from $4,257,481 in 2005 to $5,876,944 in 2006. The incresase in operating expenses is primarily due to the costs related to production coming back online in 2006 after hurricane-related damages.

Capital expenditures paid by the Working Interest Owners increased 265% from $2,587,321 in 2005 to $9,443,605 in 2006. The increase in capital expenditures during 2006 related primarily to damages caused by Hurricanes Rita and Katrina.

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, $150,109 and $115,520 in 2006 and 2005, 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.

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

In the first quarter of 2007, there was a net deposit of funds to the Special Cost Escrow Account of approximately $811,255.

In 2006, the Working Interest Owners deposited a net amount to the Trust of $1,188,000 from the Special Cost Escrow Account. As of December 31, 2006, approximately $6,839,000 remained in the Special Cost Escrow Account. In 2005, the Working Interest Owners deposited a net amount to the Trust of $239,000 from the Special Cost Escrow Account. As of December 31, 2005, approximately $5,616,000 remained in the Special Cost Escrow Account. The increased net deposits during 2006 compared to 2005 were primarily due to an increase in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties due to hurricane related damages.

Additional deposits to the Special Cost Escrow Account may be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made, including the possibility that no Royalty income would be received.

Summary By Property

Listed below is a summary of 2006 operations as compared to 2005 of the four principal Royalty Properties based on gross revenues generated during these periods combined.

Eugene Island 339

Eugene Island 339 crude oil revenues decreased $5,472,468, from $14,692,706 in 2005 to $9,220,238 in 2006, primarily due to a decrease in production. Crude oil production decreased from 312,252 barrels in 2005 to 149,887 barrels in 2006. The average price of crude oil increased from $47.05 per barrel in 2005 to $61.51 per barrel in 2006. Gas revenues decreased $6,496,531, from $7,044,350 in 2005 to $547,819 in 2006, primarily due to a decrease in gas production from 974,036 Mcf in 2005 to 83,101 Mcf in 2006 as a result of damages to the third party pipeline. The pipeline operator has advised Chevron that repair work has been suspended indefinitely. Chevron will extend the existing line within the field to connect to the existing sales point on the Eugene Island 361 platform. Gas sales are expected to resume in the third quarter of 2007. The average price received for natural gas decreased from $7.55 per Mcf in 2005 to $6.59 per Mcf in 2006. Capital expenditures increased from $931,625 in 2005 to $3,524,145 in 2006 due to hurricane-related damages. Operating expenses increased from $1,388,428 in 2005 to $2,584,319 in 2006 primarily due to increased workover expenses.

Ship Shoal 182/183

Ship Shoal 182/183 crude oil revenues increased from $16,962,280 in 2005 to $17,107,346 in 2006, due to an increase in crude oil prices from $51.32 per barrel in 2005 to $64.93 per barrel in 2006. This increase was partially offset by a decrease in crude oil production from 330,512 barrels in 2005 to 263,486 barrels in 2006. Gas revenues decreased from $6,095,350 in 2005 to $3,044,766 in 2006 due to a decrease in gas volumes from 859,925 Mcf in 2005 to 453,910 Mcf in 2006. The decrease in gas volumes resulted from no gas being produced until the third quarter of 2006 due to hurricane-related damages. The average natural gas sales price decreased from $7.23 per Mcf in 2005 to $6.71 per Mcf in 2006. Capital expenditures increased from $1,525,562 in 2005 to $5,718,239 in 2006 primarily due to hurricane-related repairs. Operating expenses increased from $1,507,792 in 2005 to $2,782,327 in 2006 due to the costs related to production coming back online in 2006 after hurricane-related damage.

West Cameron 643

West Cameron 643 gas revenues decreased from $3,163,457 in 2005 to $33,587 in 2006 due primarily to an decrease in gas volumes from 453,674 Mcf in 2005 to 6,628 Mcf in 2006. The decrease in gas volumes resulted from no gas being produced until the third quarter of 2006 at which time only a limited amount of production had begun. The average natural gas sales price decreased from $6.97 per Mcf in 2005 to $5.07 per Mcf in 2006. Operating expenses decreased from $1,324,101 in 2005 to $404,380 in 2006 due to the limited production during 2006. Capital expenditures decreased from $86,286 in 2005 to $46,156 in 2006.

East Cameron 371

East Cameron 371 gas revenues were ($99,126) in 2005 and $770 in 2006. Oil revenues were ($42,171) in 2005 and $0 in 2006. Capital expenditures increased from ($1,560) in 2005 to $315 in 2006 and operating expenses increased from ($11,116) in 2005 to $31,917 in 2006. The 2006 increases for East Cameron 371 and 2005 negative amounts were due to the Working Interest Owner including production and expenses in previous quarters related to the East Cameron 381 block wells, A-1 and A-3, in the Trust’s activity, despite the Trust not having an interest in these wells. The adjustments were made in the second quarter of 2005 to correct this error.

Years 2005 and 2004

Royalty income increased approximately 65% from $5,987,936 in 2004 to $9,854,531 in 2005 primarily due to an increase in gas revenues and crude oil and condensate revenues as discussed below.

For 2005 and 2004, the Trust had no undistributed net income or loss. Undistributed net income represents positive Net Proceeds generated during the period that were applied to an existing loss carryforward. Undistributed net loss represents negative Net Proceeds generated during the respective period. An undistributed net loss is carried forward and offset, in future periods, by positive Net Proceeds earned by the related Working Interest Owner(s).

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 4% from $17,002,431 in 2004 to $16,337,625 in 2005, partially offset by a 22% increase in the average price received for natural gas from $6.07 per Mcf in 2004 to $7.31 Mcf in 2005. Natural gas and gas products volumes decreased 21% from 2,907,514 Mcf in 2004 to 2,287,314 Mcf in 2005.

The Working Interest Owners of the East Cameron 371 property advised the Trust that, as of October 31, 2004, 26,891 Mcf had been overtaken by the Working Interest Owners from those properties. In addition, the Working Interest Owners of the East Cameron 353 and the West Cameron 643 properties advised the Trust that, as of October 31, 2004, 518 Mcf and 23,340 Mcf respectively, had been undertaken from these properties. The Partnership’s share of revenues related to the overtaken gas was included in the Partnership’s Royalty income in the periods during which the gas was sold. During 2005, all cumulative gas imbalances with the Trust were settled with the Working Interest Owner.

During the first quarter of 2004, Chevron informed the Trustees that it would make downward adjustments to revenues and production based on an improper credit to the Trust of revenues and production on Eugene Island 339. This improper credit relates to production credited from wells in which the Trust has no interest from as early as June 2002 through October 2003. The aggregate amount of these adjustments are expected to be approximately 236,650 barrels of oil or $6,449,000 for oil revenues, as well as 91,000 Mcf or $505,000 for gas revenues. Recovery by Chevron of these amounts, as well as certain capital expenditures discussed below, affected Royalty income and distributable income in the first and second quarters of 2004.

Crude Oil and Condensate

Crude oil and condensate revenues increased 44% from $22,332,005 in 2004 to $32,051,988 in 2005, due primarily to a 10% increase in crude oil and condensate volumes from 589,647 barrels in 2004 to 650,466 barrels in 2005. Additionally, average crude oil and condensate prices increased by 30% from $37.87 in 2004 to $49.28 in 2005.

Operating and Capital Expenditures

Operating expenses paid by the Working Interest Owners decreased 12% from $4,852,591 in 2004 to $4,257,481 in 2005.

Capital expenditures paid by the Working Interest Owners decreased 88% from $21,673,290 in 2004 to $2,587,321 in 2005.

Special Cost Escrow Account

In the first quarter of 2006, there was a net deposit of funds to the Special Cost Escrow Account of approximately $876,000.

In 2005, the Working Interest Owners deposited a net amount to the Trust of $239,000 from the Special Cost Escrow Account. The lower net deposits compared to 2003 were primarily due to a continued decrease in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties. As of December 31, 2005, approximately $5,616,000 remained in the Special Cost Escrow Account.

In 2004, the Working Interest Owners released a net amount to the Trust of $3,268,000 from the Special Cost Escrow Account. The release was made primarily due to a decrease in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties. As of December 31, 2004, approximately $5,376,000 remained in the Special Cost Escrow Account.

Summary By Property

Listed below is a summary of 2005 operations as compared to 2004 of the four principal Royalty Properties based on gross revenues generated during these periods combined.

Eugene Island 339

Eugene Island 339 crude oil revenues increased $7,828,063, from $6,864,643 in 2004 to $14,692,706 in 2005 primarily due to an increase in production. Crude oil production increased from 163,131 barrels in 2004 to 312,252 barrels in 2005. The average price of crude oil increased from $42.08 per barrel in 2004 to $47.05 per barrel in 2005. Gas revenues increased $2,740,898, from $4,303,452 in 2004 to $7,044,350 in 2005 primarily due to an increase in the average price received for natural gas from $6.36 per Mcf in 2004 to $7.55 per Mcf in 2005. Gas production increased from 764,093 Mcf in 2004 to 974,036 Mcf in 2005. Capital expenditures decreased from $11,290,421 in 2004 to $931,625 in 2005. Operating expenses decreased from $1,560,278 in 2004 to $1,388,428 in 2005.

Chevron has advised the Trust that the foregoing comparison does not give effect to an improper credit of revenues and production and a miscalculation of capital expenditures that was allocated during the first quarter of 2004 and recovered by Chevron during that period and in the second quarter. The aggregate amount of these adjustments for improper credits of production and revenues from as early as June 2002 through October 2003 were approximately 236,650 barrels of oil or $6,449,000 for oil revenues, as well as 91,000 Mcf or $505,000 for gas revenues. The comparison above is included without adjustment as Royalty income for these periods was calculated and paid based on these amounts.

Ship Shoal 182/183

Ship Shoal 182/183 crude oil revenues increased from $15,408,655 in 2004 to $16,962,280 in 2005, partially offset by a decrease in crude oil production from 426,449 barrels in 2004 to 330,512 barrels in 2005. The average crude oil price increased from $36.13 per barrel in 2004 to $51.32 per barrel in 2005. Gas revenues decreased from $11,179,380 in 2004 to $6,095,350 in 2005 due to a decrease in gas volumes from 1,872,307 Mcf in 2004 to 859,925 Mcf in 2005. The average natural gas sales price increased from $6.05 per Mcf in 2004 to $7.23 per Mcf in 2005. Capital expenditures decreased from $10,292,460 in 2004 to $1,525,562 in 2005. Operating expenses decreased from $2,565,505 in 2004 to $1,507,792 in 2005.

West Cameron 643

West Cameron 643 gas revenues increased from $1,100,793 in 2004 to $3,163,457 in 2005 due primarily to an increase in gas volumes from 193,978 Mcf in 2004 to 453,674 Mcf in 2005. The average natural gas sales price increased from $5.67 per Mcf in 2004 to $6.97 per Mcf in 2005. Operating expenses increased from $592,357 in 2004 to $1,324,101 in 2005, capital expenditures increased from $19,680 in 2004 to $86,286 in 2005.

East Cameron 371

East Cameron 371 gas revenues decreased from $119,196 in 2004 to ($99,126) in 2005 due primarily to a decrease in gas volumes from 24,665 Mcf in 2004 to (20,463) Mcf in 2005. Partially offset by a decrease in the average price for natural gas from $5.49 in 2004 to $4.47 in 2005. Crude oil revenues decreased from $36,215 in 2004 to ($42,171) in 2005 due primarily to a decrease in crude oil and condensate volumes. Capital expenditures decreased from $1,497 in 2004 to ($1,560) in 2005 and operating expenses decreased from $58,638 in 2004 to ($11,116) in 2005. East Cameron 371 has negative revenues, capital expenditures and operating expenses during 2005 as a result of adjustments made by the Working Interest Owner. These adjustments were due to the Working Interest Owner including production and expenses in previous quarters related to the East Cameron 381 block wells, A-1 and A-3, in the Trust’s activity, despite the Trust not having an interest in these wells. The adjustments were made in the second quarter of 2005 to correct this error.

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 to the Trust during the periods indicated. Net proceeds due to the Trust are calculated for each three month period commencing on the first day of February, May, August and November.

	Royalty Properties Year Ended December 31,(1)
	2006			2005			2004
Crude oil and condensate (bbls)	421,763			650,466			589,647
Natural gas and gas products (Mcfe)	600,477			2,287,314			2,907,514
Crude oil and condensate average price, per bbl	$	63.71		$	49.28		$	37.87
Natural gas average price, per Mcf (excluding gas products)	$	6.70		$	7.31		$	6.07
Crude oil and condensate revenues	$	26,869,007		$	32,051,988		$	22,332,005
Natural gas and gas products revenues	$	4,003,561		$	16,337,625		$	17,002,431
Production expenses	(7,277,259		)	(5,928,263		)	(6,561,459		)
Capital expenditures	(9,443,605		)	(2,587,321		)	(21,673,290		)
Undistributed net income(2)	8,368			—			—
(Provision for) Refund of Special Cost Escrow	(4,115,324		)	(451,965		)	12,854,452
Net Proceeds	$	10,044,748		$	39,422,064		$	23,954,139
Royalty interest	x25		%	x25		%	x25		%
Partnership share	$	2,511,187		$	9,855,516		$	5,988,535
Trust interest	x99.99		%	x99.99		%	x99.99		%
Trust share of Royalty Income(3)	$	2,510,936		$	9,854,531		$	5,987,936

(1) Amounts represent actual production for the twelve-month period ended on October 31 of each year, respectively.

(2) Undistributed net loss represents negative Net Proceeds generated during the respective period. An undistributed net loss is carried forward and offset, in future periods, by positive Net Proceeds, earned by the related Working Interest Owner(s). Undistributed net income represents positive Net Proceeds, generated during the respective period, that were applied to an existing loss carryforward.

(3) See Note 4 to the Notes to the Financial Statements under Item 8 of this Form 10-K for a discussion regarding uncertainty of distributions.

Off-Balance Sheet Arrangements

None.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Item 8. Financial Statements and Supplementary Data

TEL OFFSHORE TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	December 31,
	2006		2005
Assets
Cash and cash equivalents	$	3,321,587	$	3,175,221
Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,214,149 and $28,203,586 at December 31, 2006 and 2005, respectively	53,506		64,069
Total assets	$	3,375,093	$	3,239,290
Liabilities and Trust Corpus
Distribution payable to Unit holders	$	1,697,721	$	1,811,018
Reserve for future Trust expenses	1,623,866		1,364,203
Commitments and contingencies
Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding at December 31, 2006 and 2005)	53,506		64,069
Total liabilities and Trust corpus	$	3,375,093	$	3,239,290

STATEMENTS OF DISTRIBUTABLE INCOME

	Year Ended December 31,
	2006			2005			2004
Royalty income	$	2,510,936		$	9,854,531		$	5,987,936
Interest income	25,516			15,160			8,201
	2,536,452			9,869,691			5,996,137
General and administrative expenses	(579,069		)	(606,883		)	(496,611		)
(Increase)/Decrease in reserve for future Trust expenses	(259,662		)	(23,191		)	(155,319		)
Distributable income	1,697,721			9,239,617			5,344,207
Distributions per Unit (4,751,510 Units)	$	.357301		$	1.944564		$	1.124739

STATEMENTS OF CHANGES IN TRUST CORPUS

	Year Ended December 31,
	2006			2005			2004
Trust corpus, beginning of year	$	64,069		$	90,053		$	154,619
Distributable income	1,697,721			9,239,617			5,344,207
Distribution payable to Unit holders	(1,697,721		)	(9,239,617		)	(5,344,207		)
Amortization of net overriding royalty interest	(10,563		)	(25,984		)	(64,566		)
Trust corpus, end of year	$	53,506		$	64,069		$	90,053

The accompanying notes are an integral part of these financial statements

TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)

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, 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, 2006 the reserve amount was $1,623,866. Through the first three quarters 2006, the Trust used $486,400 from the Trust’s cash reserve account to pay the Trust’s general and administrative expenses when insufficient Royalty income was received by the Trust. Amounts were withheld from fourth quarter 2006 distributable income to increase the reserve to its calculated balance. At December 31, 2006 the reserve amount was $3,321,587.

(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 $38.3 million (unaudited) as of October 31, 2006. 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.

The Trust is currently administered by The Bank of New York Trust Company, N.A., 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 Daniel O. Conwill, IV, Gary C. Evans and Jeffrey S. Swanson (“Individual Trustees”), as trustees (“Trustees”).

(2) Net Overriding Royalty Interest

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

TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)

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, and the Royalty Properties owned by TEPI were assigned to Chevron on May 1, 2002. Crude oil sales from the Chevron and TEPI properties added together accounted for approximately 99%, for 2006, 2005 and 2004 of crude oil revenues from the Royalty Properties. Sales to ChevronTexaco accounted for approximately 99%, 99% and 94% of total gas revenues from the Royalty Properties during 2006, 2005 and 2004, respectively.

The Trust’s share of Royalty income was reduced by approximately $350,927, $418,000 and $496,000 in 2006, 2005 and 2004, 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

The financial statements of the Trust are prepared on the following basis:

(a) Royalty income 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 are recorded when paid, except for the cash reserved for future general and administrative expenses; and

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

The changes in reserve for future Trust expenses 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.

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

TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)

subjective and is based on the Corporate Trustee’s best estimate (based on advice and information provided by the Managing General Partner and working interest owners) of assumptions concerning expected future conditions. There were no write downs taken in the periods presented.

The Special Cost Escrow account (see Note 6) 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.

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.

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

(4) Distributions to Unit Holders

During the quarter ended March 31, 2004, a Working Interest Owner made certain negative adjustments to previously reported Net Proceeds (See Note 5). As a result of these negative adjustments, the Trust at March 31, 2004 had a loss carryforward of $3,307,628. In the second quarter of 2004, Net Proceeds were offset by the loss carryforward of $3,307,628 with a resulting loss carryforward balance of $0 at June 30, 2004. No distributable income was available to Unit holders in the second quarter since the Trust recoups expenses being paid from the reserve for Trust expense that the Trustees have established for anticipated future expenses. During the quarter ended September 30, 2004, the Trust resumed distributions as the reserve for trust expenses had been funded.

TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)

Mexico, which has increased current and future levels of expenditures. The reduced oil and gas production and increased costs reduced the cash income distributions to unitholders significantly during 2006 and may continue to affect cash income distributions during a portion or all of 2007. During the fourth quarter 2006, the Trust resumed distributions. The fourth quarter distribution of $1.7 million was paid on January 11, 2007. On March 30, 2007, the Trust announced its first quarter distribution of approximately $1.2 million.

(5) Negative Adjustments

During the quarter ended March 31, 2004, a Working Interest Owner informed the Trust that it had made errors in prior periods which resulted in prior period Net Proceeds being overstated. This Working Interest Owner, Chevron, which is also the Managing General Partner of the Partnership, has advised the Trust that these errors consisted of:

· Eugene Island 339—a $6,953,982 gross revenue adjustment to reverse revenues previously credited to the Trust for interest in wells that the Trust does not hold an interest, a $98,797 gross operating expense adjustment and a $573,382 adjustment to increase previous capital expenditures.

· Ship Shoal 182/183—a $1,336,287 gross adjustment to reverse revenues previously credited to the Trust primarily for double-counted production and a $1,855,976 adjustment to correct previously recorded adjustments to capital expenditures.

· South Timbalier 36/37 (Royalty Properties associated with Chevron Texaco)—a $495,425 gross adjustment to reverse the effects of clerical errors.

The Trust recorded the adjustments during the first quarter of 2004, which resulted in a loss carryforward of $3,307,628 as of March 31, 2004. In the second quarter of 2004, Net Proceeds were sufficient to fully offset the loss carryforward of $3,307,628, resulting in no further loss carryforward.

(6) 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 $150,109, $115,520 and $66,700 for 2006, 2005 and 2004, respectively, serves to reduce the Trust’s share of allocated production costs. As of December 31, 2006, 2005 and 2004, approximately $6,839,000, $5,616,000 and $5,376,000, 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 account 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

TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)

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.

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.

In the first quarter of 2007, there was a net deposit of funds to the Special Cost Escrow Account of approximately $811,000. Deposits to the Special Cost Escrow Account may be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made.

In 2006, the Working Interest Owners deposited a net amount of approximately $1,188,239 into the Special Cost Escrow Account. In 2005, the Working Interest Owners deposited a net amount of approximately $239,000 into the Special Cost Escrow Account. The net deposits were made primarily due to changes in the estimate of projected capital expenditures, production costs and abandonment costs of the Royalty Properties.

(7) Federal Income Tax Matters

(8) Commitments and Contingencies

The Working Interest Owners have advised the Trust that, although they believe that they are 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 which 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 report prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants. 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, 2006, with no provision for future increases or decreases except for periodic price redeterminations in accordance with existing gas contracts.

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 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

TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS (Continued)

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 $38.3 million as of October 31, 2006 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.

Distributable income for the Partnership for the periods ended December 31, 2006, 2005 and 2004 included net proceeds relating to production of reserves from the Royalty Properties for the twelve months ended October 31, 2006, 2005 and 2004, respectively.

(10) Selected Quarterly Financial Data (Unaudited)

Summarized quarterly financial data is as follows:

	First		Second		Third		Fourth
2006*:
Royalty income	—		—		—		$	2,510,936
Distributable income	—		—		—		$	1,697,721
Distributions per Unit	$	0.00000	$	0.000000	$	0.000000	$	0.357301
2005*:
Royalty income	$	526,972	$	1,895,230	$	5,591,822	$	1,840,507
Distributable income	$	316,435	$	1,664,525	$	5,447,639	$	1,811,018
Distributions per Unit	$	0.066597	$	0.350315	$	1.146507	$	0.381145

* Royalty income and distributable income were decreased or increased in certain quarters due to deposits to or releases from the Special Cost Escrow Account as discussed in Note 6 above.

See Note 4 for a discussion regarding uncertainty of distributions.

*****

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 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 and 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 Trust Unit holders have no control over the operation or development of the Royalty Properties and have little influence over operation or development” in the Trust’s Form 10-K, and “Note 5—Negative Adjustments” of the financial statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operating” relating to operating information on East Cameron 371 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 year ended December 31, 2006, there has been no change in the Corporate Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Corporate Trustee’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 the Working Interest Owners or the managing general partner of the Partnership.

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 Trust Company, N.A. serves as the Corporate Trustee, and Daniel O. Conwill, IV, Gary C. Evans 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, or a nominating committee.

Section 16(a) Beneficial Ownership Reporting.

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 2006.

Item 11. Executive Compensation.

Not applicable.

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 the date of this report.

(b) Security Ownership of Management.

Not applicable.

(c) Changes in Control.

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

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

Each of the Working Interest Owners owns interests, for its own account, in leases which 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 ChevronTexaco accounted for approximately 99% of total crude oil revenues from the Royalty Properties during 2006, 2005 and 2004. During such years, all of Chevron’s natural gas and natural gas liquids relative to the Royalty Properties were committed and sold to Chevron Texaco Natural Gas.

The Trust’s share of Royalty income was reduced by approximately $351,000, $418,000 and $496,000 in 2006, 2005 and 2004, 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 2006, 2005 and 2004.

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 following table presents fees for professional audit services rendered by Deloitte & Touche LLP for the audit of Tel Offshore Trust financial statements for 2006 and 2005 and fees billed for other services rendered by Deloitte & Touche LLP.

	2006		2005
Audit fees	$	160,000	$	154,000
Audit-related fees	—		—
Tax fees	8,000		7,500
All other fees	—		—
Total fees	$	168,000	$	161,500

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:

		Page in This Form 10-K
Report of Independent Registered Public Accounting Firm		43
Statements of Assets, Liabilities and Trust Corpus		44
Statements of Distributable Income		44
Statements of Changes in Trust Corpus		44
Notes to Financial Statements		45

(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 Trust Company, N.A. succeeded JPMorgan Chase Bank as Corporate Trustee. JPMorgan Chase Bank is successor by mergers to the original name of the Corporate Trustee, Texas Commerce Bank National Association.

			SEC File or Registration Number		Exhibit Number
4	(a)*	Trust Agreement dated as of January 1, 1983, among Tenneco Offshore Company, Inc., Texas Commerce Bank National Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as individual trustees (Exhibit 4(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)		0-6910	4(a)
4	(b)*	Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)		0-6910	4(b)
4	(c)*	Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)		0-6910	4(c)
4	(d)*	Amendments to TEL Offshore Trust Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)		0-6910	4(d)
4	(e)*	Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)		0-6910	4(e)
10	(a)*	Purchase Agreement, dated as of December 7, 1984 by and between Tenneco Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)		0-6910	10(a)
10	(b)*	Consent Agreement, dated November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)		0-6910	10(b)
10	(c)*	Assignment and Assumption Agreement, dated November 17, 1988, between Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)		0-6910	10(c)
10	(d)*	Gas Purchase and Sales Agreement Effective September 1, 1993 between Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company (Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of TEL Offshore Trust)		0-6910	10(d)
31		Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32		Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Texas		76-6004064
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
The Bank of New York Trust Company, N.A, Trustee 919 Congress Avenue Austin, Texas		78701
(Address of principal executive offices)		(Zip Code)

		TEL OFFSHORE TRUST
		By:		THE BANK OF NEW YORK TRUST COMPANY, N.A., Corporate Trustee
		By:		/s/ MIKE ULRICH
				Mike Ulrich
				Vice President

		Signature		Date
THE BANK OF NEW YORK TRUST COMPANY, N.A., Corporate Trustee
By:	/s/ MIKE ULRICH		April 2, 2007
	Mike Ulrich, Vice President &
	Trust Officer
INDIVIDUAL TRUSTEES
/s/ DANIEL O. CONWILL, IV			April 2, 2007
Daniel O. Conwill, IV, Individual Trustee
/s/ GARY C. EVANS			April 2, 2007
Gary C. Evans, Individual Trustee
/s/ JEFFREY S. SWANSON			April 2, 2007
Jeffrey S. Swanson, Individual Trustee

Date: April 2, 2007	/s/ MIKE ULRICH
	Mike Ulrich,
	*Vice President*
	The Bank of New York Trust Company, N.A.

	THE BANK OF NEW YORK TRUST COMPANY, N.A.
	Trustee for TEL Offshore Trust
	By:		/s/ MIKE ULRICH
			Mike Ulrich
			Vice President

Title of Each Class		Name of Each Exchange on which Registered
None		None

		Page
	PART I
Item 1.	Business	4
	Description of the Trust	4
	Description of the Units	9
	Termination of the Trust	13
	Royalty Income, Distributable Income and Total Assets	14
	Description of Royalty Properties	15
	Marketing	25
	Competition and Regulation	26
Item 1A.	Risk Factors	29
Item 1B.	Unresolved Staff Comments	33
Item 2.	Properties	33
Item 3.	Legal Proceedings	33
Item 4.	Submission of Matters to a Vote of Security Holders	33
	PART II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	35
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	42
Item 8.	Financial Statements and Supplementary Data	42
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	53
Item 9A.	Controls and Procedures	53
Item 9B.	Other Information	53
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	53
Item 11.	Executive Compensation	54
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	54
Item 13.	Certain Relationships and Related Transactions, and Director Independence	54
Item 14.	Principal Accountant Fees and Services	55
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	55
SIGNATURES		57