**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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**FORM 10-Q**

**x**                              QuarterlyReport Pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934 for the quarterly period ended September 30, 2006

**or**

**o**                                 TransitionReport Pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934 for the Transition Period from *                       *to*                       *

**CommissionFile Number: 0-06910**

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**TEL OFFSHORE TRUST**

(Exact Name of Registrantas Specified in its Charter)

| **Texas**                                              |   | **76-6004064**       |
|--------------------------------------------------------|--------|----------------------|
| (State of  Incorporation,                              |   | (I.R.S. Employer     |
| or Organization)                                       |   | Identification  No.) |
| **The Bank of New York Trust  Company, N.A., Trustee** |   | ** **           |
| **Global  Corporate Trust**                            |   | ** **           |
| **221  West Sixth Street**                             |   | ** **           |
| **Austin,  Texas**                                     |   | **78701**            |
| (Address of  Principal                                 |   | (Zip Code)           |
| Executive  Offices)                                    |   |                 |

 

Registrant’s TelephoneNumber, Including Area Code: **800-852-1422**

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required tofile such reports), and (2) has been subject to such filing requirementsfor the past 90 days. Yes þ No o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of “accelerated filer and largeaccelerated filer” in Rule 12b-2 of the Exchange Act.

(Check one): LargeAccelerated Filer o  AcceleratedFiler o  Non-accelerated filer þ

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

Indicatethe number of shares outstanding of each of the registrant’s classes of commonstock, as of the latest practicable date. As of November 14, 2006—4,751,510Units of Beneficial Interest in TEL Offshore Trust.

 

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**NOTE REGARDINGFORWARD-LOOKING STATEMENTS**

This Form 10-Q includes “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934,as amended. All statements other than statements of historical facts includedin this Form 10-Q are forward-looking statements. Although theWorking Interest Owners (as defined herein) have advised the Trust that theybelieve that the expectations reflected in the forward-looking statementscontained herein are reasonable, no assurance can be given that suchexpectations will prove to have been correct. Important factors that couldcause actual results to differ materially from expectations (“CautionaryStatements”) are disclosed in this Form 10-Q, including, withoutlimitation, in conjunction with the forward-looking statements includedin this Form 10-Q. A summary of certain principal risks andCautionary Statements is also included in the Trust’s Annual Report on Form 10-Kfor the year ended December 31, 2005 under Part I, Item 1A. “Risk Factors.”All subsequent written and oral forward-looking statements attributableto the Trust or persons acting on its behalf are expressly qualified in theirentirety by the Cautionary Statements.

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**PART I—FINANCIALINFORMATION**

**Item 1.**                        FinancialStatements.

**STATEMENTS OFASSETS, LIABILITIES AND TRUST CORPUS(Unaudited)**

| ** **                                                                                                                                       | ** ** | **September 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| **Assets**                                                                                                                                       |       |                         |       |                        |       |   |   |
| Cash and cash  equivalents                                                                                                                       |       | $                            | 877,804    |                        |       | $ | 3,175,221 |   |   |
| Net overriding  royalty interest in oil and gas properties, net of  accumulated amortization of $28,210,667 and $28,203,586,   respectively |       | 56,988                       |       |                        | 64,069     |   |   |
| Total assets                                                                                                                                     |       | $                            | 934,792    |                        |       | $ | 3,239,290 |   |   |
| **Liabilities  and Trust Corpus**                                                                                                                |       |                         |       |                        |       |   |   |
| Distribution  payable to Unit holders                                                                                                            |       | $                            | —     |                        |       | $ | 1,811,018 |   |   |
| Reserve for  future Trust expenses                                                                                                               |       | 877,804                      |       |                        | 1,364,203  |   |   |
| Commitments and  contingencies                                                                                                                   |       |                         |       |                        |       |   |   |
| Trust corpus  (4,751,510 Units of beneficial interest authorized and outstanding)                                                                |       | 56,988                       |       |                        | 64,069     |   |   |
| Total liabilities and  Trust corpus                                                                                                              |       | $                            | 934,792    |                        |       | $ | 3,239,290 |   |   |

 

**STATEMENTS OFDISTRIBUTABLE INCOME(Unaudited)**

| ** **                                                | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-----------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| Royalty income                                            |       | $                                                    | —     |                                                | $          | 5,591,822 |   | $ | — |   | $ | 8,014,024 |   |
| Interest income                                           |       | 3,628                                                |       | 3,850                                               |       | 12,410 |   | 9,708 |   |
|                                                      |       | 3,628                                                |       | 5,595,672                                           |       | 12,410 |   | 8,023,732 |   |
| Decrease/(Increase) in reserve for future Trust  expenses |       | 133,181                                              |       | 19,270                                              |       | 486,400 |   | (101,495 | ) |
| General and  administrative expenses                      |       | (136,809                                             | )          | (167,303                                            | )          | (498,810 | ) | (493,638 | ) |
| Distributable  income                                     |       | $                                                    | —     |                                                | $          | 5,447,639 |   | $ | — |   | $ | 7,428,599 |   |
| Distributions per Unit  (4,751,510 Units)                 |       | $                                                    | .000000    |                                                | $          | 1.146507 |   | $ | .000000 |   | $ | 1.563419 |   |

 

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

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**STATEMENTS OF CHANGES IN TRUST CORPUS(Unaudited)**

| ** **                                       | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|--------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                       | ** ** | **2006**                                             | ** ** | **2005**                                            | ** ** | **2006** | ** ** | **2005** | ** ** |
| Trust corpus,  beginning of period               |       | $                                                    | 59,614     |                                                | $          | 78,420 |   | $ | 64,069 |   | $ | 90,053 |   |
| Distributable  income                            |       | —                                               |       | 5,447,639                                           |       | — |   | 7,428,599 |   |
| Distribution  payable to Unit holders            |       | —                                               |       | (5,447,639                                          | )          | — |   | (7,428,599 | ) |
| Amortization of  net overriding royalty interest |       | (2,626                                               | )          | (9,148                                              | )          | (7,081 | ) | (20,781 | ) |
| Trust corpus, end of  period                     |       | $                                                    | 56,988     |                                                | $          | 69,272 |   | $ | 56,988 |   | $ | 69,272 |   |

 

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

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**Tel Offshore TrustNotes to Financial Statements(unaudited)**

**Note 1—RecentEvents—Cash Income Distribution**

Based upon thesignificantly reduced oil and gas production due to hurricane-related damagesin the areas where our oil and gas properties are located during the secondhalf of 2005, the current and future expected deficit for expenditures subjectto recovery from future royalty income, estimated future capital expenditureprojects for repairs or tie-backs to alternative pipelines, and additional potentialfuture exploratory activities being considered by Working Interest Owners, theCorporate Trustee does not expect there to be any cash income distributionsduring 2006 and potentially during a portion or all of 2007.

**Note 2—TrustOrganization**

Tenneco Offshore Company, Inc. (“Tenneco Offshore”)created the TEL Offshore Trust (“Trust”) effective January 1, 1983,pursuant to the Plan of Dissolution (“Plan”) approved by Tenneco Offshore’sstockholders on December 22, 1982. In accordance with the Plan, the TELOffshore Trust Partnership (“Partnership”) was formed in which the Trust owns a99.99% interest and Tenneco Oil Company (“Tenneco”) initially owned a .01%interest. In general, the Plan was effected by transferring an overridingroyalty interest (“Royalty”) equivalent to a 25% net profits interest in theoil and gas properties (the “Royalty Properties”) of TennecoExploration, Ltd. (“Exploration I”) located offshore Louisiana to thePartnership and issuing certificates evidencing units of beneficial interest inthe Trust (“Units”) in liquidation and cancellation of Tenneco Offshore’scommon stock.

On October 31, 1986, Exploration I was dissolvedand the oil and gas properties of Exploration I were distributed to Tennecosubject to the Royalty. Tenneco, who was then serving as the Managing GeneralPartner of the Partnership, assumed the obligations of Exploration I, includingits obligations under the instrument conveying the Royalty to the Partnership(the “Conveyance”). The dissolution of Exploration I had no impact on futurecash distributions to holders of units of beneficial interest.

On November 18, 1988, Chevron U.S.A., Inc. (“Chevron”)acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco,including all of the Royalty Properties. As a result of the acquisition,Chevron replaced Tenneco as the Working Interest Owner and Managing GeneralPartner of the Partnership. Chevron also assumed Tenneco’s obligations underthe 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, includingfour of the Royalty Properties. The four Royalty Properties acquired byPennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 andEugene Island 208. As a result of such acquisition, PennzEnergy replacedChevron as the Working Interest Owner of such properties on October 30,1992. PennzEnergy also assumed Chevron’s obligations under the Conveyance withrespect to these properties.

On December 1, 1994, Texaco Exploration andProduction Inc. (“TEPI”) acquired two of the Royalty Properties fromChevron. The Royalty Properties acquired by Texaco were West Cameron 643 andEast Cameron 371/381. As a result of such acquisitions, TEPI replacedChevron as the Working Interest 

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Owner of such propertieson December 1, 1994. TEPI also assumed Chevron’s obligations under theConveyance 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 367property from PennzEnergy. As a result of such acquisitions, SONAT and Amocoreplaced PennzEnergy as the Working Interest Owners of the East Cameron 354 andEugene Island 367 properties, respectively, on October 1, 1995 and alsoassumed PennzEnergy’s obligations under the Conveyance with respect to theseproperties.

Effective January 1, 1998, Energy ResourceTechnology, Inc. (“ERT”) acquired the East Cameron 354 property fromSONAT. As a result of such acquisition, ERT replaced SONAT as the WorkingInterest Owner of the East Cameron 354 property effective January 1, 1998,and also assumed SONAT’s obligations under the Conveyance with respect to suchproperty. In October 1998, Amerada Hess Corporation (“Amerada”) acquiredthe East Cameron 354 property from ERT effective January 1, 1998. As aresult of such acquisition, Amerada replaced ERT as the Working Interest Ownerof the East Cameron 354 property effective January 1, 1998, and alsoassumed ERT’s obligations under the Conveyance with respect to this property.

Effective January 1, 2000 PennzEnergy and DevonEnergy Corporation (Nevada) merged into Devon Energy Production Company L.P. (“Devon”).As a result of such merger, Devon replaced PennzEnergy as the Working InterestOwner of Eugene Island 348 and Eugene Island 208 properties effective January 1,2000, and also assumed PennzEnergy’s obligations under the Conveyance withrespect to these properties.

On October 9, 2001, a wholly owned subsidiary ofChevron Corporation, a Delaware corporation, merged (the “Merger”) with andinto Texaco Inc., a Delaware corporation (“Texaco”), pursuant to anAgreement and Plan of Merger, dated as of October 15, 2000. As a result ofthe Merger, Texaco Inc. became a wholly owned subsidiary of ChevronCorporation, and Chevron Corporation changed its name to “ChevronTexacoCorporation” in connection with the Merger (ChevronTexaco Corporation isreferred to herein as “ChevronTexaco”). Accordingly, the properties referred toherein by Chevron and Texaco are each now controlled by subsidiaries ofChevronTexaco.

On May 1, 2002, TEPI assigned all of itsinterests in West Cameron 643 and East Cameron 371/381 to Chevron. Accordingly,pursuant to the Conveyance of the Royalty Properties, net profits interest willbe calculated for the collective Royalty Properties owned by Chevron after thisdate.

On June 6, 2003, Anadarko Petroleum Corporation (“Anadarko”)acquired, among other interests, a 25% Working Interest in the EastCameron 354 field subject to a 25% Net Profit Interest property fromAmerada effective April 1, 2003. As a result of this transaction, Anadarkoreplaced Amerada as the Working Interest Owner of East Cameron 354effective July 1, 2003 and also assumed Amerada’s obligations under theConveyance with respect to said property.

Effective October 1, 2004, Apache acquiredAnadarko’s interest in East Cameron 354 and assumed Anadarko’s obligationsunder the conveyance with respect to this property.

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

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Unless the context inwhich such terms are used indicates otherwise, in these Notes to FinancialStatements the terms “Working Interest Owner” and “Working Interest Owners”generally refer to the owner or owners of the Royalty Properties (TennecoExploration, Ltd. through October 31, 1986; Tenneco for periods from October 31,1986 until November 18, 1988; Chevron with respect to all RoyaltyProperties for periods from November 18, 1988 until October 30, 1992,and with respect to all Royalty Properties except East Cameron 354, EugeneIsland 348, Eugene Island 367 and Eugene Island 208 for periods from October 30,1992 until December 1, 1994, and with respect to the same propertiesexcept West Cameron 643 thereafter; PennzEnergy/Devon with respect to EastCameron 354, Eugene Island 348, Eugene Island 367 and Eugene/Devon Island208 for periods from October 30, 1992 until October 1, 1995, and withrespect to Eugene Island 348 and Eugene Island 208 thereafter; TEPI withrespect to West Cameron 643 and East Cameron 371/381 for periodsbeginning on or after December 1, 1994 until May 1, 2002; SONAT withrespect to East Cameron 354 for periods beginning on or after October 1,1995; and Amoco with respect to Eugene Island 367 for periods beginning on orafter October 1, 1995; Amerada with respect to East Cameron 354 forperiods beginning on or after January 1, 1998; Chevron with respect toWest Cameron 643 and East Cameron 371/381 on and after May 1, 2002;and Anadarko with respect to East Cameron 354 on and after July 1, 2003until October 2004: and Apache with respect to East Cameron 354 afterOctober 1, 2004).

The Bank of New York TrustCompany, N.A. is the Corporate Trustee of the Trust. The Bank of New York TrustCompany succeeded JPMorgan Chase Bank, N.A. as the Corporate Trustee effectiveOctober 2, 2006 pursuant to an agreement under which The Bank of New YorkTrust Company acquired substantially all of JPMorgan Chase’s corporate trustbusiness.

**Note 3—Basisof Accounting**

The accompanying unauditedfinancial information has been prepared by The Bank of New York Trust Company,N.A. (“Corporate Trustee”) in accordance with the instructions to Form 10-Q.The accompanying financial information does not include all of the informationrequired by accounting principles generally accepted in the United States ofAmerica for complete financial statements, although the Corporate Trustee andthe individual trustees (collectively, the “Trustees”) believe that thedisclosures are adequate to make the information presented not misleading. Theinformation furnished reflects all adjustments which are, in the opinion of theTrustees, necessary for a fair presentation of the results for the interimperiods presented. The financial information should be read in conjunction withthe financial statements and notes thereto included in the Trust’s AnnualReport on Form 10-K for the year ended December 31, 2005.

The financialstatements of the Trust are prepared on the following basis:

(a)          Royalty income isrecorded when received, including the effect of overtaken or undertakenpositions and negative or positive adjustments, by the Corporate Trustee on thelast business day of each calendar quarter. In addition, Royalty incomeincludes amounts related to funds deposited or released from the Special CostEscrow account—see (c); and

(b)         Trust general andadministrative expenses are recorded when paid, except for the cash reservedfor future general and administrative expenses; and

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(c)          The funds deposited orreleased from the Special Cost Escrow account are recorded at the time ofpayment or receipt. The Special Cost Escrow account is an account of theWorking Interest Owners and is not reflected in the financial statements of theTrust.

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

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 expensesincludes both changes of amounts deemed necessary by the Trustees and relateddistributions, as well as amounts paid from the reserve during periods when theTrust has insufficient income to pay Trust expenses.

The Trust reviews the net overriding royalty interestin oil and gas properties for possible impairment whenever events orcircumstances indicate the carrying amount of the asset may not be recoverable.If there is an indication of impairment, the Trust prepares an estimate offuture cash flows (undiscounted and without interest charges) expected toresult from the use of the asset and its eventual disposition. If these cashflows are less than the carrying amount of the asset, an impairment loss isrecognized to write down the asset to its estimated fair value. Preparation ofestimated expected future cash flows is inherently subjective and is based onthe Corporate Trustee’s best estimate of assumptions concerning expected futureconditions. There were no write downs taken in the periods presented.

The Special Cost Escrow account (Note 6) isestablished for the future costs to be incurred to plug and abandon wells,dismantle and remove platforms, pipelines and other production facilities andfor the estimated amount of future capital expenditures on the RoyaltyProperties. The funds held in the Special Cost Escrow account are not reflectedin the financial statements of the Trust. However, funds deposited to orreleased from the Special Cost Escrow account are included in Royalty income.

The preparation of financial statements requires theTrustees to make use of estimates and assumptions that affect amounts reportedin the financial statements as well as certain discounts. Actual results coulddiffer from those estimates.

The amount of cashdistributions by the Trust is dependent on, among other things, the salesprices for oil and gas produced from the Royalty Properties and the quantitiesof oil and gas sold. It should be noted that substantial uncertainties existwith regard to future oil and gas prices, which are subject to materialfluctuations due to changes in production levels and pricing and other actionstaken by major petroleum producing nations, as well as the regional supply anddemand for gas, weather, industrial growth, conservation measures, competitionand other variables. The Trust does not enter into any hedging transactions onfuture production.

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**Note 4—NetOverriding Royalty Interest**

The Royalty entitles theTrust to its share (99.99%) of 25% of the Net Proceeds attributable to theRoyalty Properties. The Conveyance, dated January 1, 1983, provides thatthe Working Interest Owners will calculate, for each period of three monthscommencing the first day of February, May, August and November, an amountequal to 25% of the Net Proceeds from their oil and gas properties for theperiod. Generally, “Net Proceeds” means the amounts received by the WorkingInterest Owners from the sale of minerals from the Royalty Properties lessoperating and capital costs incurred, management fees and expensereimbursements owing to the Managing General Partner of the Partnership,applicable taxes other than income taxes, and a Special Cost Escrow account.The Special Cost Escrow account (See Note 6) is established for the futurecosts to be incurred to plug and abandon wells, dismantle and remove platforms,pipelines and other production facilities, and for the estimated amount offuture capital expenditures on the Royalty Properties. Net Proceeds do notinclude amounts received by the Working Interest Owners as advance gaspayments, “take-or-pay” payments or similar payments unless and until suchpayments are extinguished or repaid through the future delivery of gas.

**Note 5—Distributionsto Unit Holders**

In accordance with theprovisions of the Trust Agreement, generally all Net Proceeds received by theTrust, net of Trust general and administrative expenses and any cash reservesestablished for the payment of contingent or future obligations of the Trust,are distributed currently to the Unit holders. Such distributions are referredto as “distributable income.” The amounts distributed are determined on aquarterly basis and are payable to Unit holders of record as of the lastbusiness day of each calendar quarter. However, cash distributions are made inJanuary, April, July and October and include interest earned from thequarterly record date to the date of distribution.

**Note 6—Special CostEscrow Account**

The Special Cost Escrow is an account of the WorkingInterest Owners, and it is described herein for informational purposes only.The Conveyance provides for the reserve of funds for estimated future “SpecialCosts” of plugging and abandoning wells, dismantling platforms and other costsof abandoning the Royalty Properties, as well as for the estimated amount offuture drilling projects and other capital expenditures on the RoyaltyProperties. As provided in the Conveyance, the amount of funds to be reservedis determined based on certain factors, including estimates of aggregate futureproduction costs, aggregate future Special Costs, aggregate future net revenuesand actual current net profits interest. Deposits into this account reducecurrent distributions and are placed in an escrow account and invested inshort-term certificates of deposit. Such account is herein referred to as the “SpecialCost Escrow” account. The Trust’s share of interest generated from the SpecialCost Escrow account serves to reduce the Trust’s share of allocated productioncosts. Special Cost Escrow funds will generally be utilized to pay SpecialCosts to the extent there are not adequate current net profits interest to paysuch costs. Special Costs that have been paid are no longer included in theSpecial Cost Escrow calculation. Deposits to the Special Cost Escrow accountwill generally be made when the balance in the Special Cost Escrow account is lessthan 125% of estimated future Special Costs and there is a Net RevenuesShortfall (a calculation of the excess of estimated future costs over estimatedfuture net revenues pursuant to a formula contained in the Conveyance). Whenthere is not a Net Revenues Shortfall, amounts in the Special Cost Escrowaccount 

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will generally bereleased, to the extent that Special Costs have been incurred. Amounts in theSpecial Cost Escrow account generally will also be released when the balance insuch account exceeds 125% of estimated future Special Costs. As of September 30,2006, $7,123,673 remained in the Special Cost Escrow account. The funds held inthe Special Cost Escrow account are not reflected in the financial statementsof the Trust.

Chevron, in its capacity asManaging General Partner of the Partnership, has advised the Trust thatadditional deposits to the Special Cost Escrow account may be required infuture periods in connection with other production costs, other abandonmentcosts, other capital expenditures and changes in the estimates and factorsdescribed above. Such deposits could result in a significant reduction inRoyalty income in the periods in which such deposits are made, including thepossibility that no Royalty income would be received in such periods.

**Note 7—ReserveFor Future Trust Expenses**

The Trust made adetermination in 1998 to maintain a cash reserve equal to three times theaverage expenses of the Trust during each of the past three years to providefor future administrative expenses in connection with the winding up of theTrust. The reserve amount for 2006 was calculated to be $1,504,904. During thenine months ended September 30, 2006, the Trust used $486,400 from theTrust’s cash reserve account to pay the Trust’s general and administrativeexpenses when insufficient Royalty income was received by the Trust, reducingthe reserve amount held by the Trust to $877,804 as of September 30, 2006.The reserve amount at September 30, 2005 was $1,442,509. Amounts will bewithheld to increase this reserve to its calculated balance when the Trustreceives Royalty income in future periods.

**Note 8—Texas MarginTax**

The Texas legislature recently passed H.B. 3, 79thLeg., 3d C.S. (2006), which was signed into law on May 18, 2006. H.B. 3 significantlyreforms the Texas franchise tax system and replaces it with a new Texas margintax system. The margin tax expands the type of entities subject to tax togenerally include all active business entities, including corporations andlimited liability companies currently subject to the franchise tax. The newmargin tax also will apply to the following common entity types that are notcurrently subject to tax: general and limited partnerships (unless otherwiseexempt), limited liability partnerships, trusts (unless otherwise exempt),business trusts, business associations, professional associations, joint stockcompanies, holding companies, and joint ventures. The effective date of themargin tax is January 1, 2008, but the tax generally will be imposed ongross revenues generated in 2007 and thereafter.

Trusts and partnerships that meet statutoryrequirements and receive at least 90% of their gross income from designatedsources, including royalties from mineral properties, and do not receive morethan 10% of their income from operating an active trade or business, aregenerally exempt from the margin tax as “passive entities.” Although the incomeof the Trust consists primarily of royalty income from the sale of crude oiland natural gas, there is no clear authority that the Trust satisfies all themargin tax statutory requirements for the exemption for passive entities toapply. Therefore, prior to clarification by additional legislative action orthe issuance of applicable administrative rules promulgated by the TexasComptroller, it is uncertain whether the Trust would be exempt from the margintax as a passive entity or subject to the margin tax at the trust level. TheCorporate Trustee is continuing to evaluate the impacts of HB3 to the Trust.

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**Item2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations.

**CriticalAccounting Policies**

The financialstatements of the Trust are prepared on the following basis:

(a)          Royalty income isrecorded when received, including the effect of overtaken or undertakenpositions and negative or positive adjustments, by the Corporate Trustee on thelast business day of each calendar quarter. In addition, Royalty incomeincludes amounts related to funds deposited or released from the Special CostEscrow account—see (c); and

(b)         Trust general andadministrative expenses are recorded when paid, except for the cash reservedfor future general and administrative expenses; and

(c)          The funds deposited orreleased from the Special Cost Escrow account are recorded at the time ofpayment or receipt. The Special Cost Escrow account is an account of theWorking Interest Owners and is not reflected in the financial statements of theTrust.

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

The Trustees, includingthe Corporate Trustee, have no authority over, have not evaluated and make nostatement concerning, the internal control over financial reporting of theWorking Interest Owners.

**Financial Review**

**Three Months Ended September 30,2006 and 2005**

There were no distributions to the Unit holders forthe three months ended September 30, 2006 as compared to $5,447,639, or$1.146507 per Unit, for the same period in 2005. There was no distributableincome for the third quarter of 2006 primarily as a result of damage caused tothe Royalty Properties by Hurricanes Rita and Katrina discussed below in “—OperationalReview” and a required deposit to the Special Cost Escrow account. As a resultof such events, the Corporate Trustee does not expect there to be any cashincome distributions during 2006 and potentially during a portion or all of2007.

Crude oil and condensaterevenues decreased $2,626,143, or 28%, to $6,859,202 in the third quarter of2006 as compared to $9,485,345 in the third quarter of 2005, due to a 45%decrease in crude oil and condensate volume to 102,070 barrels in the thirdquarter of 2006 from 186,210 barrels in the third quarter of 2005. The decreasedue to lower production volumes was partially offset by a 32% increase in theaverage price of crude oil and condensate to $67.20 per barrel in the thirdquarter of 2006 from $50.94 per barrel in the third quarter of 2005.

Gas revenues decreased $4,463,666, or 86%, to $701,359in the third quarter of 2006 from $5,165,025 in the third quarter of 2005, dueto a decrease in gas volumes of 85% to 107,013 Mcf in the third quarter of 2006from 708,345 Mcf in the third quarter of 2005. The average price received fornatural gas was 

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$6.55 per Mcf in thethird quarter of 2006, compared to $7.29 per Mcf in the third quarter of 2005.Gas products revenue decreased 99% to $4,297 in the third quarter of 2006 from$335,178 in the third quarter of 2005, primarily due to a 99% decrease inproduction volumes to 4,092 gallons in the third quarter of 2006 from 422,508gallons in the third quarter of 2005.

The Trust’s share of capital expenditures increased$1,053,931, from $515,985 in the third quarter of 2005 to $1,569,916 in thethird quarter of 2006. The increase in capital expenditures for the thirdquarter of 2006 related primarily to damages caused by Hurricanes Rita andKatrina.

The Trust did not have undistributed net income in thethird quarter of 2006.

In the third quarter of 2005, there was a net releaseof funds from the Special Cost Escrow account. The Trust’s share of the fundsreleased during this quarter was $2,337,030.

In the third quarter of2006, there was a net deposit of funds into the Special Cost Escrow account.The Trust’s share of the net funds deposited was $592,718. As of September 30,2006, $7,123,673 remained in the Special Cost Escrow account. The Special CostEscrow is set aside for estimated abandonment costs and future capitalexpenditures, as provided for in the Conveyance. For additional information relatingto the Special Cost Escrow, see “—Special Cost Escrow Account” below.

**Nine Months EndedSeptember 30, 2006 and 2005**

There were no distributions to the Unit holders forthe nine months ended September 30, 2006 as compared to $7,428,599, or $1.563419per Unit, for the nine months ended September 30, 2005. The decrease indistributable income during 2006 resulted primarily to damages caused to theRoyalty Properties by Hurricanes Rita and Katrina and required deposits to theSpecial Cost Escrow account.

Crude oil and condensate revenues decreased $7,940,499,or 31%, to $17,897,350 in the first nine months of 2006 as compared to$25,837,849 for the same period in 2005, due to damages caused by HurricanesRita and Katrina, which was partially offset by an increase in the averageprice of crude oil and condensate from $47.26 per barrel to $61.51 per barrel,respectively, during these periods.

Gas revenues decreased $10,749,418, or 89%, to$1,284,660 in the first nine months of 2006 from $12,034,078 for the sameperiod in 2005, due to a 6% decrease in the average price received for naturalgas to $6.63 per Mcf in the first nine months of 2006 from $7.05 per Mcf in thesame period of 2005, in addition to a decrease in gas volumes of 89% to 193,820Mcf in the first nine months of 2006 from 1,706,002 Mcf for the same period in2005. Gas products revenue decreased $1,047,675 or 90%, to $116,406 in thefirst nine months of 2006 from $1,164,081 in the same period of 2005, primarilydue to a decrease in production volume of 1,312,650 gallons, or 90%, to 148,354gallons in the first nine months of 2006 from 1,461,004 gallons in the sameperiod of 2005.

The Trust’s share of capital expenditures increased$6,441,002, from $2,510,890 in the first nine months of 2005 to $8,951,892 inthe same period of 2006. The increase in capital expenditures for the firstnine months of 2006 related primarily to damages caused by Hurricanes Rita andKatrina.

The Trust did not have undistributed net income in thefirst nine months of 2006. 

In the first nine monthsof 2006, there was a net deposit of funds into the Special Cost Escrow account.The Trust’s share of the net funds deposited was $1,472,956. In the first ninemonths of 2005, 

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therewas a net release of funds into the Special Cost Escrow account. The Trust’sshare of the funds released was $61,287. As of September 30, 2006, $7,123,673remained in the Special Cost Escrow account. The Special Cost Escrow is setaside for estimated abandonment costs and future capital expenditures, asprovided for in the Conveyance. For additional information relating to theSpecial Cost Escrow, see “—Special Cost Escrow Account” below.

**Reserve for FutureTrust Expenses**

In accordance with theprovisions of the Trust Agreement, generally all Royalty income received by theTrust, net of Trust general and administrative expenses and any cash reservesestablished for the payment of contingent or future obligations of the Trust,are distributed currently to the Unit holders. In the first quarter of 1998,the Trust determined that the Trust’s cash reserve was sufficient at that timeto provide for future administrative expenses in connection with the winding upof the Trust. The Trust determined that a cash reserve equal to three times theaverage expenses of the Trust during each of the past three years wassufficient at this time to provide for future administrative expenses inconnection with the winding up of the Trust. The reserve amount for 2006 wascalculated to be $1,504,904. During the third quarter of 2006, the Trustused $133,181 from the Trust’s cash reserve account to pay the Trust’s generaland administrative expenses when insufficient Royalty income was received bythe Trust, reducing the reserve amount held by the Trust to $877,804 as of September 30,2006. The reserve amount at September 30, 2005 was $1,442,509.Amounts will be withheld to increase this reserve to its calculated balancewhen the Trust receives Royalty income in future periods.

**Other**

The amount of cashdistributed by the Trust is dependent on, among other things, the sales pricesand quantities of oil and gas produced from the Royalty Properties as well ascapital expenditures by the Working Interest Owners that may or may not beincluded in the Special Cost Escrow account. It should be noted thatsubstantial uncertainties exist with regard to future oil and gas prices, whichare subject to material fluctuations due to changes in production levels andpricing and other actions taken by major petroleum producing nations, as wellas the regional supply and demand for oil and gas, weather, industrial growth,conservation measures, competition and other variables.

**Operational Review**

The following operationalinformation has been based on information provided to the Corporate Trustee byChevron as the Managing General Partner of the Partnership and by theapplicable Working Interest Owners. The Trustees have no control over theseoperations or internal controls relating to this information.

At the end of October 2005, approximately half ofChevron oil-equivalent production in the Gulf of Mexico remained shut in due todamages from hurricanes in the third quarter. The time it will take to resumethis production is uncertain, and some of the volumes may not be sufficientlyeconomic to restore. As of November 14, 2006, Eugene Island 339 gas sales havenot resumed, but production is currently expected to resume at the end of 2006 aftera new sales point is built by the operator to replace the Eugene Island 338sales point destroyed by Hurricane Rita and, assuming transportationavailability is fully restored on a third party transmission pipeline thatincurred significant hurricane-related damages. The 

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operator of this pipelinehas advised that the hurricane-related damages on their pipeline were extensive,and the Working Interest Owner has advised the Trustee that it is currentlyevaluating various alternatives for transportation as production is alsorestored. The Working Interest Owner has also advised the Trust that it isworking on a project to compress and re-inject gas to the B-5 well, whichwould allow the operator to increase oil production and to limit flaring ofgas. Eugene Island 339 oil production increased during the third quarter of 2006and is expected to increase further during the fourth quarter of 2006 as theB-5 well gas injection project is completed. On Ship Shoal 182/183, gasproduction and sales resumed in July and full production is expected to resumein the fourth quarter of 2006. On West Cameron 643, production was shut in fromSeptember 2005 following Hurricane Rita’s major damage to variousplatforms, but limited gas production resumed in late July 2006 before thewells loaded up and additional repairs were required.

**Three Months EndedSeptember 30, 2006 and 2005**

*Volumes and dollar amountsdiscussed below represent amounts recorded by the Working Interest Ownersunless otherwise specified.*

Ship Shoal 182/183 crude oil revenues decreased from$5,285,070 in the third quarter of 2005 to $4,175,138 in the third quarter of2006, partially offset by an increase in the average crude oil price from $52.31per barrel in the third quarter of 2005 to $67.93 per barrel for the sameperiod in 2006. Crude oil production decreased from 101,042 barrels in thethird quarter of 2005 to 61,465 barrels in the third quarter of 2006. Gas revenuesdecreased from $2,006,142 in the third quarter of 2005 to $663,176 in the thirdquarter of 2006, primarily due to a decrease in gas production. Gas volumesdecreased from 272,592 Mcf in the third quarter of 2005 to 101,558 Mcf in thethird quarter of 2006. The natural gas sales price decreased from $7.36 per Mcfin the third quarter of 2005 to $6.53 per Mcf in the third quarter of 2006.Capital expenditures increased from $316,858 in the third quarter of 2005 to $605,845in the third quarter of 2006. Operating expenses increased from $408,785 in thethird quarter of 2005 to $692,241 for the same period in 2006.

Eugene Island 339 crude oil revenues decreased from$4,088,063 in the third quarter of 2005 to $2,555,170 in the third quarter of2006. There was a decrease in crude oil production from 82,927 barrels in thethird quarter of 2005 to 38,706 barrels in the third quarter of 2006. Theaverage price of crude oil increased from $49.30 per barrel in the thirdquarter of 2005 to $66.02 in the third quarter of 2006. Gas revenues decreasedfrom $1,575,929 in the third quarter of 2005 to $0 in the third quarter of 2006due to damages caused by Hurricanes Rita and Katrina that caused gas productionto decrease from 212,419 Mcf in the third quarter of 2005 to 0 Mcf in the thirdquarter of 2006. Capital expenditures increased from $162,771 in the third quarterof 2005 to $945,904 in the third quarter of 2006, primarily due to a new oilsales pipeline and sales point as well as a gas injection compressor project.Operating expenses increased from $399,954 in the third quarter of 2005 to$1,266,577 for the same period in 2006, mostly due to workover expenses on well# B-12.

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West Cameron 643 gas revenues decreased from$1,549,572 in the third quarter of 2005 to $0 in the third quarter of 2006 dueto damage caused by Hurricanes Rita and Katrina that caused gas production todecrease from 218,322 Mcf in the third quarter of 2005 to 0 Mcf in the thirdquarter of 2006. Although limited gas production resumed in late July 2006,those revenues were not included in third-quarter 2006 results of operations. Operatingexpenses decreased from $140,268 in the third quarter of 2005 to $97,716 forthe same period in 2006. Capital expenditures decreased from $30,821 in thethird quarter of 2005 to $0 in the third quarter of 2006.

East Cameron 371/381 crudeoil revenues decreased from $197 in the third quarter of 2005 to $0 in thethird quarter of 2006. Gas revenues decreased from $8,681 in the third quarterof 2005 to $0 in the third quarter of 2006. There was no production at EastCameron 371/381 due to hurricane-related damages. Operating expenses increasedfrom $4,167 in the third quarter of 2005 to $17,235 in the third quarter of 2006.There were no capital expenses in the third quarter of 2005 or 2006.

**Nine Months Ended September 30, 2006 and 2005**

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

Ship Shoal 182/183 crudeoil revenues decreased from $13,383,678 in the first nine months of 2005 to$12,404,718 in the first nine months of 2006, due to a decline in crude oilproduction from 272,333 barrels in the first nine months of 2005 to 197,212barrels in the first nine months of 2006. The decrease was partially offset byan increase in the average crude oil price from $49.14 per barrel in the firstnine months of 2005 to $62.90 per barrel for the same period in 2006. Gasrevenues decreased from $5,068,228 in the first nine months of 2005 to $663,176in first nine months of 2006 primarily due to a significant decrease in gasvolumes from 715,058 Mcf in the first nine months of 2005 to 101,558 Mcf forthe same period in 2006. This decrease in gas volumes resulted from no gas beingproduced until the third quarter of 2006 as a result of hurricane-related damages.The average natural gas sales price decreased from $7.09 per Mcf in the firstnine months of 2005 to $6.53 in the first nine months of 2006. Capitalexpenditures increased from $1,477,630 in the first nine months of 2005 to$5,374,876 in the same period of 2006, primarily due to hurricane-relatedrepairs. Operating expenses increased from $1,079,065 for the first nine monthsof 2005 to $1,703,593 for the first nine months of 2006, due to the costsrelated to production coming back online in 2006 after hurricane-related damage.

Eugene Island 339 crudeoil revenues decreased from $12,140,854 in the first nine months of 2005 to$5,145,024 in the first nine months of 2006, primarily due to a decrease involumes from 268,139 barrels in the first nine months of 2005 to 88,134 barrelsin the first nine months of 2006. The price of crude oil increased from $45.28per barrel in the first nine months of 2005 to $58.38 per barrel in the firstnine months of 2006. Gas revenues decreased from $4,753,004 in the first ninemonths of 2005 to $547,819 in the first nine months of 2006, primarily due to adecrease in production from 665,035 Mcf for the first nine months of 2005 to83,101 Mcf for the same period in 2006. Capital expenditures increased from$905,891 in the first nine months of 2005 to $3,510,917 in the first ninemonths of 2006 due to hurricane-related damages. Operating expenses increasedfrom $1,059,559 for the first nine months of 2005 to $1,842,775 for the firstnine months of 2006, primarily due to increased workover expenses.

West Cameron 643 gasrevenues decreased from $2,197,951 in the first nine months of 2005 to $0 inthe first nine months of 2006 due to a decrease in gas volumes from 328,735 Mcfin the first nine months of 

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2005 to0 Mcf for the same period in 2006. Operating expenses decreased from $1,192,832in the first nine months of 2005 to $315,623 for the first nine months of 2006.Capital expenditures decreased from $83,913 in the first nine months of 2005 to$46,156 in the first nine months of 2006.

East Cameron 371/381 crudeoil revenues were ($42,369) in the first nine months of 2005 and $0 for thesame period in 2006. Gas revenues were ($81,934) in the first nine months of2005 to $0 for the same period in 2006. Operating expenses increased from($15,451) in the first nine months of 2005 to $25,436 in the first nine monthsof 2006. There were no capital expenditures in the first nine months of 2006 ascompared to ($1,560) in the first nine months of 2005. The 2006 increases forEast Cameron 371/381 and 2005 negative amounts were due to the Working InterestOwner including production and expenses in previous quarters related to theEast Cameron 381 block wells, A-1 and A-3, in the Trust’s activity, despite theTrust not having an interest in these wells. The adjustments were made in thesecond quarter of 2005 to correct this error.

**Future Net Revenuesand Termination of the Trust**

Based on a reserve studyprovided to the Trust by DeGolyer and MacNaughton, independent petroleumengineers, it was estimated, that as of October 31, 2005, future netrevenues attributable to the Trust’s royalty interests were estimated at$48.0 million. Estimates of proved oil and gas reserves attributable tothe Partnership’s royalty interest are based on existing economic and operatingconditions in effect at October 31, 2005 in order to correspond withdistributions to the Trust. Such reserve study also indicates thatapproximately 71% of the future net revenues from the Royalty Properties areexpected to be received by the Trust during the next three years. In addition,because the Trust will terminate in the event estimated future net revenuesfall below $2.0 million, it would be possible for the Trust to terminateeven though some or all of the Royalty Properties continued to have remainingproductive lives. Upon termination of the Trust, the Trustees will sell for cashall of the assets held in the Trust estate and make a final distribution toUnit holders of any funds remaining after all Trust liabilities have beensatisfied. The estimates of future net revenues discussed above are subject tolarge variances from year to year and should not be construed as exact. Thereare numerous uncertainties present in estimating future net revenues for theRoyalty Properties. The estimate may vary depending on changes in market pricesfor crude oil and natural gas, the recoverable reserves, including thediscovery of new proved reserves as a result of exploratory drilling, annualproduction and costs assumed by DeGolyer and MacNaughton. In addition, futureeconomic and operating conditions as well as results of future drilling plansmay cause significant changes in such estimate. The discussion set forth aboveis qualified in its entirety by reference to the Trust’s Annual Report on Form 10-Kfor the year ended December 31, 2005. The Form 10-K is available atthe SEC’s website *www.sec.gov*.

**Special Cost EscrowAccount**

The Conveyance provides for reserving funds forestimated future “Special Costs” of plugging and abandoning wells, dismantlingplatforms and other costs of abandoning the Royalty Properties, as well as forthe estimated amount of future drilling projects and other capital expenditureson the Royalty Properties. As provided in the Conveyance, the amount of fundsto be reserved is determined based on factors including estimates of aggregatefuture production costs, aggregate future Special Costs, aggregate future netrevenues and actual current net proceeds. Deposits into this account reducecurrent 

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distributions and areplaced in an escrow account and invested in short-term certificates of deposit.Such account is herein referred to as the “Special Cost Escrow” account. TheTrust’s share of interest generated from the Special Cost Escrow account servesto reduce the Trust’s share of allocated production costs.

Special Cost Escrow funds will generally be utilizedto pay Special Costs to the extent there are not adequate current net proceedsto pay such costs. Special Costs that have been paid are no longer included inthe Special Cost Escrow calculation. Deposits to the Special Cost Escrowaccount will generally be made when the balance in the Special Cost Escrowaccount is less than 125% of estimated future Special Costs and there is a NetRevenues Shortfall (a calculation of the excess of estimated future costs overestimated future net revenues pursuant to a formula contained in theConveyance). When there is not a Net Revenues Shortfall, amounts in the SpecialCost Escrow account will generally be released, to the extent that SpecialCosts have been incurred. Amounts in the Special Cost Escrow account generallywill also be released when the balance in such account exceeds 125% ofestimated future Special Costs. In the first nine months of 2006, there was anet deposit of funds to the Special Cost Escrow account of $1,472,956. In thefirst nine months of 2005, there was a net release of funds to the Special CostEscrow account of $61,287.

As of September 30, 2006, $7,123,673 remained inthe Special Cost Escrow account.

Chevron, in its capacityas Managing General Partner of the Partnership, has advised the Trust that additionaldeposits to the Special Cost Escrow account may be required in future periodsin connection with other production costs, other abandonment costs, othercapital expenditures and changes in the estimates and factors described above.Such deposits could result in a significant reduction in Royalty income in theperiods in which such deposits are made, including the possibility that noRoyalty income would be received in such periods.

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**Overview ofProduction, Prices and Net Proceeds**

Thefollowing schedule provides a summary of the volumes and weighted averageprices for crude oil and condensate and natural gas recorded by the WorkingInterest Owners for the Royalty Properties, as well as the Working InterestOwners’ calculations of the net proceeds and the royalties paid to the Trustduring the periods indicated. Net proceeds due to the Trust are calculated foreach three month period commencing on the first day of February, May, August andNovember.

| ** **                                                   | ** ** | **Royalty Properties  Three Months Ended  September 30,(1)** | ** ** |
|--------------------------------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2006**                                                                         | ** ** | **2005** | ** ** |
| Crude oil and  condensate (bbls)                             |       | 102,070                                                                          |       | 186,210 |   |
| Natural gas and  gas products (Mcfe)                         |       | 107,598                                                                          |       | 768,703 |   |
| Crude oil and  condensate average price, per bbl             |       | $                                                                                | 67.20      |   | $ | 50.94 |   |
| Natural gas  average price, per Mcf (excluding gas products) |       | $                                                                                | 6.55       |   | $ | 7.29 |   |
| Crude oil and  condensate revenues                           |       | $                                                                                | 6,859,202  |   | $ | 9,485,345 |   |
| Natural gas and  gas products revenues                       |       | 705,657                                                                          |       | 5,500,203 |   |
| Production  expenses                                         |       | (2,427,953                                                                       | )          | (1,469,787 | ) |
| Capital  expenditures                                        |       | (1,569,916                                                                       | )          | (515,985 | ) |
| Undistributed Net  Loss (Income)(2)                          |       | (1,504,221                                                                       | )          | 0 |   |
| Refund  Of/(Provision for) Special Cost Escrow               |       | (2,062,769                                                                       | )          | 9,369,747 |   |
| **Net  Proceeds**                                            |       | —                                                                           |       | 22,369,524 |   |
| Royalty interest                                             |       | x25                                                                              | %          | x25 | % |
| Partnership share                                            |       | —                                                                           |       | 5,592,381 |   |
| Trust interest                                               |       | x99.99                                                                           | %          | x99.99 | % |
| Trust share of Royalty  Income                               |       | $                                                                                | —     |   | $ | 5,591,822 |   |

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(1)          Amounts represent actualproduction for the three-month period ended July of each yearrespectively.

(2)          Undistributednet loss represents negative Net Proceeds generated during the respectiveperiod. An undistributed net loss is carried forward and offset, in futureperiods, by positive Net Proceeds earned by the related Working InterestOwner(s). Undistributed net income represents positive Net Proceeds, generatedduring the respective period, that were applied to an existing losscarryforward.

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| ** **                                                   | ** ** | **Royalty Properties  Nine Months Ended  September 30,(1)** | ** ** |
|--------------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2006**                                                                        | ** ** | **2005** | ** ** |
| Crude oil and  condensate (bbls)                             |       | 290,987                                                                         |       | 546,766 |   |
| Natural gas and  gas products (Mcfe)                         |       | 215,013                                                                         |       | 1,914,717 |   |
| Crude oil and  condensate average price, per bbl             |       | $                                                                               | 61.51      |   | $ | 47.26 |   |
| Natural gas  average price, per Mcf (excluding gas products) |       | $                                                                               | 6.63       |   | $ | 7.05 |   |
| Crude oil and  condensate revenues                           |       | $                                                                               | 17,897,350 |   | $ | 25,837,848 |   |
| Natural gas and  gas products revenues                       |       | 1,401,066                                                                       |       | 13,198,159 |   |
| Production  expenses                                         |       | (4,908,342                                                                      | )          | (4,710,966 | ) |
| Capital  expenditures                                        |       | (8,951,892                                                                      | )          | (2,510,890 | ) |
| Undistributed Net  Loss (Income)(2)                          |       | 11,513                                                                          |       | 0 |   |
| Refund of/  (Provision for) Special Cost Escrow              |       | (5,449,695                                                                      | )          | 245,148 |   |
| **Net  Proceeds**                                            |       | —                                                                          |       | 32,059,300 |   |
| Royalty interest                                             |       | x25                                                                             | %          | x25 | % |
| Partnership share                                            |       | —                                                                          |       | 8,014,825 |   |
| Trust interest                                               |       | x99.99                                                                          | %          | x99.99 | % |
| Trust share of Royalty  Income                               |       | $                                                                               | —     |   | $ | 8,014,023 |   |

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(1)   Amounts represent actual production for the nine-month periodended July of each year respectively.

(2)          Undistributednet loss represents negative Net Proceeds generated during the respectiveperiod. An undistributed net loss is carried forward and offset, in futureperiods, by positive Net Proceeds earned by the related Working InterestOwner(s). Undistributed net income represents positive Net Proceeds, generatedduring the respective period, that were applied to an existing losscarryforward. As of September 30, 2006, the loss carryforward was $11,513.

**Item 3.**                        Quantitativeand Qualitative Disclosures About Market Risk.

No material changes haveoccurred since our Annual Report on Form 10-K for the year ended December 31,2005. Reference is also made to Note 2 of the Notes to FinancialStatements included in Part I, Item 1 of this Form 10-Q.

**Item 4.**                        Controlsand Procedures.

*Evaluationof disclosure controls and procedures.  **The*Corporate Trustee maintains disclosurecontrols and procedures designed to ensure that information required to bedisclosed by the Trust in the reports that it files or submits under theSecurities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded,processed, summarized and reported within the time periods specified in the SEC’srules and forms. Disclosure controls and procedures include, withoutlimitation, controls and procedures designed to ensure that information requiredto be disclosed by the Trust in the reports that it files or submits under theExchange Act is accumulated and communicated by Chevron, as the managinggeneral partner of the Partnership, and the working interest owners to The Bankof New York Trust Company, N.A., as Corporate Trustee of the Trust, and itsemployees who participate in the preparation of the Trust’s periodic reports asappropriate to allow timely decisions regarding required disclosure.

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As of the end of the period covered by this report, theCorporate Trustee carried out an evaluation of the Trustee’s disclosurecontrols and procedures. Mike Ulrich, as Vice President of the CorporateTrustee, has concluded that the disclosure controls and procedures of the Trustwere effective at that time.

Due to the contractual arrangements of (i) theTrust Agreement, (ii) the Partnership Agreement and (iii) the rightsof the Partnership under the Conveyance regarding information furnished by theworking interest owners, the Trustees rely on (A) information provided bythe Working Interest Owners, including historical operating data, plans forfuture operating and capital expenditures, reserve information and informationrelating to projected production, (B) information from the managing generalpartner of the Partnership, including information that is collected from theWorking Interest Owners, and (C) conclusions and reports regarding reserves by the Trust’s independentreserve engineers. See Part I, Item 1A. “Risk Factors—None of the Trustees,the Trust nor its Unit holders control the operation or development of theRoyalty Properties and have little influence over operation or development” and“—The Trustee relies on the Working Interest Owners and managing generalpartner for information regarding the Royalty Properties” in the Trust’s AnnualReport on Form 10-K for the year ended December 31, 2005, and “Note5—Negative Adjustments” of the financial statements and “Management’sDiscussion and Analysis of Financial Condition and Results of Operations”relating to operating information on East Cameron 371/381 included in theAnnual Report on Form 10-K for the year ended December 31, 2005for a description of certain risks relating to these arrangements and relianceand applicable adjustments to operating information when reported by theWorking Interest Owners to the Corporate Trustee and recorded in the Trust’sresults of operations.

*Changesin Internal Control Over Financial Reporting.**  *During the three months ended September 30,2006, there has been no change in the Corporate Trustee’s internal control overfinancial reporting that has materially affected, or is reasonably likely tomaterially affect, the Corporate Trustee’s internal control over financialreporting relating to the Trust. The Corporate Trustee notes for purposes ofclarification that it has no authority over, and makes no statement concerning,the internal control over financial reporting of the Working Interest Owners orthe managing general partner of the Partnership.

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**PART II—OTHERINFORMATION**

**Item 1A.**                RiskFactors.

There have not been anymaterial changes from risk factors previously disclosed in response toItem 1A to Part I of the Trust’s Annual Report on Form 10-Kfor the year ended December 31, 2005.

**Item 6.**                        Exhibits.

(Asteriskindicates exhibit previously filed with the Securities and Exchange Commissionand incorporated herein by reference. The Bank of New York Trust Company, N.A.,is the successor trustee from JPMorgan Chase Bank, N.A. effective in October2006. JPMorgan Chase Bank, N.A. was formerly known as The Chase Manhattan Bankand was 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 the year ended  December 31, 1992 of TEL Offshore Trust) |       | 0-06910                                 |       | 4(a)                 |
| 4(b)*  |       | —     | Agreement of General Partnership of TEL Offshore  Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust,  dated January 1, 1983 (Exhibit 4(b) to Form 10-K  for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                      |       | 0-06910                                 |       | 4(b)                 |
| 4(c)*  |       | —     | Conveyance of Overriding Royalty Interests from  Exploration I to the Partnership (Exhibit 4(c) to Form 10-K  for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                       |       | 0-06910                                 |       | 4(c)                 |
| 4(d)*  |       | —     | Amendments to TEL Offshore Trust Agreement, dated  December 7, 1984 (Exhibit 4(d) to Form 10-K  for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                                     |       | 0-06910                                 |       | 4(d)                 |
| 4(e)*  |       | —     | Amendment to the Agreement of General Partnership of  TEL Offshore Trust Partnership, effective Offshore Trust  (Exhibit 4(e) to Form 10-K for the year ended  December 31, 1992 of TEL Offshore Trust)                                                                                                                                               |       | 0-06910                                 |       | 4(e)                 |
| 10(a)* |       | —     | Purchase Agreement, dated as of December 7,  1984 by and between Tenneco Oil Company and Tenneco Offshore II Company  (Exhibit 10(a) to Form 10-K for year ended  December 31, 1992, of TEL Offshore Trust)                                                                                                                            |       | 0-06910                                 |       | 10(a)                |
| 10(b)* |       | —     | Consent Agreement, dated November 16, 1988,  between TEL Offshore Trust and Tenneco Oil Company  (Exhibit 10(b) to Form 10-K for year ended  December 31, 1988 of  TEL Offshore Trust)                                                                                                                                                           |       | 0-06910                                 |       | 10(b)                |

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| 10(c)* |   | — | Assignment and Assumption Agreement, dated  November 17, 1988, between Tenneco Oil Company and TOC-Gulf  of Mexico Inc. (Exhibit 10(c) to Form 10-K for year  ended December 31, 1988 of TEL Offshore Trust)           |   | 0-06910 |   | 10(c)  |
|--------|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|---------|--------|--------|
| 10(d)* |   | — | Gas Purchase and Sales Agreement Effective  September 1, 1993 between Tennessee Gas Pipeline Company and Chevron  U.S.A. Production Company (Exhibit 10(d) to Form 10-K  for year ended December 31, 1993 of TEL Offshore Trust) |   | 0-06910 |   | 10(d)  |
| 31     |   | — | Rule 13a-14(a) /  15d-14(a) Certification                                                                                                                                                                                                  |   |    |   |   |
| 32     |   | — | Section 1350  Certification                                                                                                                                                                                                                          |   |    |   |   |

 

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.

|                         | TEL OFFSHORE TRUST |
|-------------------------|--------------------|
|                    | By:                | The Bank of New York  Trust Company, N. A. Corporate Trustee |
|                    | By:                | /s/  MIKE ULRICH |
| ** **              | *** ***       | **Mike  Ulrich** |
| ** **              | *** ***       | ***Vice  President*** |
| Date: November 14, 2006 | *** ***       | *** *** |

 

The Registrant, TEL Offshore Trust, has no principalexecutive officer, principal financial officer, board of directors or personsperforming similar functions. Accordingly, no additional signatures areavailable and none have been provided.

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