**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

**Forthe quarterly period ended June 30, 2006**

**or**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACTOF 1934

**Forthe transition periodfrom                    to                  **

**CommissionFile Number: 0-06910**

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**TEL OFFSHORE TRUST**

(Exact Name of Registrantas Specified in its Charter)

| **Texas**                                 |   | **76-6004064**       |
|-------------------------------------------|--------|----------------------|
| (State or Other Jurisdiction  of          |   | (I.R.S. Employer     |
| Incorporation, or  Organization)          |   | Identification  No.) |
| **JPMorgan Chase Bank, N.A.**             |   | ** **           |
| **Institutional  Trust Services**         |   | ** **           |
| **221  West Sixth Street**                |   | ** **           |
| **Austin,  Texas**                        |   | **78701**            |
| (Address of  Principal Executive Offices) |   | (Zip Code)           |

 

**(800) 852-1422**

(Registrant’s TelephoneNumber, Including Area Code)

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 x  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 x

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

Indicatethe number of shares outstanding of each of the registrant’s classes of commonstock, as of the latest practicable date. As of August 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 2005 Annual Report on Form 10-Kunder Part I, Item 1A. “Risk Factors.” All subsequent written and oralforward-looking statements attributable to the Trust or persons acting onits behalf are expressly qualified in their entirety by the CautionaryStatements.

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**PART I—FINANCIALINFORMATION**

**Item 1.**                        FinancialStatements.

**TEL OFFSHORE TRUSTSTATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS(Unaudited)**

| ** **                                                                                                                                | ** ** | **June 30,    2006** | ** ** | **December 31,    2005** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------|------------|-----------------------------------------|------------|
| **Assets**                                                                                                                                |       |                                |       |                                    |       |   |   |
| Cash and cash  equivalents                                                                                                                |       | $                                   | 1,010,984  |                                    |       | $ | 3,175,221 |   |   |
| Net overriding  royalty interest in oil and gas properties, net of accumulated amortization  of $28,208,041 and $28,203,586, respectively |       | 59,614                              |       |                                    | 64,069     |   |   |
| Total assets                                                                                                                              |       | $                                   | 1,070,598  |                                    |       | $ | 3,239,290 |   |   |
| **Liabilities  and Trust Corpus**                                                                                                         |       |                                |       |                                    |       |   |   |
| Distribution  payable to Unit holders                                                                                                     |       | $                                   | —     |                                    |       | $ | 1,811,018 |   |   |
| Reserve for  future Trust expenses                                                                                                        |       | 1,010,984                           |       |                                    | 1,364,203  |   |   |
| Commitments and  contingencies                                                                                                            |       |                                |       |                                    |       |   |   |
| Trust corpus  (4,751,510 Units of beneficial interest authorized and outstanding)                                                         |       | 59,614                              |       |                                    | 64,069     |   |   |
| Total liabilities and  Trust corpus                                                                                                       |       | $                                   | 1,070,598  |                                    |       | $ | 3,239,290 |   |   |

 

**STATEMENTS OFDISTRIBUTABLE INCOME(Unaudited)**

| ** **                                                | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|-----------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                | ** ** | **2006**                                        | ** ** | **2005**                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
| Royalty income                                            |       | $                                               | —     |                                          | $          | 1,895,230 |   | $ | — |   | $ | 2,422,202 |   |
| Interest income                                           |       | 3,990                                           |       | 3,037                                         |       | 8,782 |   | 5,858 |   |
|                                                      |       | 3,990                                           |       | 1,898,267                                     |       | 8,782 |   | 2,428,060 |   |
| (Increase)  decrease in reserve for future Trust expenses |       | 188,829                                         |       | (51,859                                       | )          | 353,219 |   | (120,765 | ) |
| General and  administrative expenses                      |       | (192,819                                        | )          | (181,883                                      | )          | (362,001 | ) | (326,335 | ) |
| Distributable  income                                     |       | $                                               | —     |                                          | $          | 1,664,525 |   | $ | — |   | $ | 1,980,960 |   |
| Distributions per Unit  (4,751,510 Units)                 |       | $                                               | .000000    |                                          | $          | .350315 |   | $ | .000000 |   | $ | .416912 |   |

 

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**STATEMENTSOF CHANGES IN TRUST CORPUS(Unaudited)**

| ** **                                       | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|--------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                       | ** ** | **2006**                                        | ** ** | **2005**                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
| Trust corpus,  beginning of period               |       | $                                               | 61,580     |                                          | $          | 87,452 |   | $ | 64,069 |   | $ | 90,053 |   |
| Distributable  income                            |       | —                                          |       | 1,664,525                                     |       | — |   | 1,980,960 |   |
| Distribution  payable to Unit holders            |       | —                                          |       | (1,664,525                                    | )          | — |   | (1,980,960 | ) |
| Amortization of  net overriding royalty interest |       | (1,966                                          | )          | (9,032                                        | )          | (4,455 | ) | (11,633 | ) |
| Trust corpus, end of  period                     |       | $                                               | 59,614     |                                          | $          | 78,420 |   | $ | 59,614 |   | $ | 78,420 |   |

 

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIALSTATEMENTS**

**(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 Owner of such properties on December 1,1994. TEPI also assumed Chevron’s obligations under the Conveyance with respectto these properties.

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On October 1,1995, SONAT Exploration Company (“SONAT”) acquired the East Cameron 354property from PennzEnergy. In addition, on October 1, 1995, AmocoProduction Company (“Amoco”) acquired the Eugene Island 367 property fromPennzEnergy. As a result of such acquisitions, SONAT and Amoco replacedPennzEnergy 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 withrespect to these properties.

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.

Unless the context in which such terms are usedindicates otherwise, in these Notes to Financial Statements the terms “WorkingInterest Owner” and “Working Interest Owners” generally refer to the owner orowners of the Royalty Properties (Tenneco Exploration, Ltd. 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 Propertiesexcept East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island208 for periods from October 30, 1992 until December 1, 1994, andwith respect to the same properties except West Cameron 

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643 thereafter;PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, EugeneIsland 367 and Eugene/Devon Island 208 for periods from October 30, 1992until October 1, 1995, and with respect to Eugene Island 348 and EugeneIsland 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron371/381 for periods beginning on or after December 1, 1994 until May 1,2002; SONAT with respect 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; andAnadarko with respect to East Cameron 354 on and after July 1, 2003 until October 2004:and Apache with respect to East Cameron 354 after October 1, 2004).

On April 8, 2006,JPMorgan Chase Bank, N.A., and Bank of New York announced an agreement pursuantto which Bank of New York would acquire JPMorgan Chase’s corporate trustbusiness. The transaction has been approved by both companies boards ofdirectors. Subject to regulatory approvals, the transaction is expected to closelate in the third quarter or fourth quarter of 2006. The transaction is notexpected to have any material effect on the Trust.

**Note 2—Basisof Accounting**

The accompanying unaudited financial information hasbeen prepared by JPMorgan Chase Bank, N.A. (“Corporate Trustee”) inaccordance with the instructions to Form 10-Q and does not includeall of the information required by accounting principles generally accepted inthe United States of America for complete financial statements, although theCorporate Trustee and the individual trustees (collectively, the “Trustees”)believe that the disclosures are adequate to make the information presented notmisleading. The information furnished reflects all adjustments which are, inthe opinion of the Trustees, necessary for a fair presentation of the resultsfor the interim periods presented. The financial information should be read inconjunction with the financial statements and notes thereto included in theTrust’s Annual Report on Form 10-K for the year ended December 31,2005.

The financial statements of the Trust are prepared onthe 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, 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.

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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 to resultfrom the use of the asset and its eventual disposition. If these cash flows areless than the carrying amount of the asset, an impairment loss is recognized towrite down the asset to its estimated fair value. Preparation of estimatedexpected future cash flows is inherently subjective and is based on theCorporate 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 5) is establishedfor the future costs to be incurred to plug and abandon wells, dismantle andremove platforms, pipelines and other production facilites and for theestimated amount of future capital expenditures on the Royalty Properties. Thefunds held in the Special Cost Escrow account are not reflected in thefinancial statements of the Trust. However, funds deposited to or released fromthe 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.

**Note 3—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 5) 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 4—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 a 

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quarterlybasis and are payable to Unit holders of record as of the last business day ofeach calendar quarter. However, cash distributions are made in January, April, July andOctober and include interest earned from the quarterly record date to thedate of distribution. See Note 8.

**Note 5—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 isless than 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 will generally be released, to the extent that Special Costs have beenincurred. Amounts in the Special Cost Escrow account generally will also bereleased when the balance in such account exceeds 125% of estimated futureSpecial Costs. As of June 30, 2006, $6,496,132 remained in the SpecialCost Escrow account. The funds held in the Special Cost Escrow account are notreflected in the financial statements of the Trust.

Chevron, in its capacityas Managing 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 6—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 $1,512,997. During thesix months ended June 30, 2006, the Trust used $353,219 from the Trust’scash reserve account to pay the Trust’s general and administrative expenseswhen insufficient Royalty income was received by the Trust, reducing thereserve amount held by the Trust to $1,010,984 as of June 30, 2006. Thereserve amount at June 30, 2005 was $1,461,779. Amounts will be withheldto increase this reserve to its calculated balance when the Trust receivesRoyalty income in future periods.

**Note 7—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. 3significantly reforms the Texas franchise tax system and replaces it with a newTexas margin tax system. The margin tax expands the type of entities subject totax to generally include all active 

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business entities,including corporations and limited liability companies currently subject to thefranchise tax. The new margin tax also will apply to the following commonentity types that are not currently subject to tax: general and limitedpartnerships (unless otherwise exempt), limited liability partnerships, trusts(unless otherwise exempt), business trusts, business associations, professionalassociations, joint stock companies, holding companies, and joint ventures. Theeffective date of the margin tax is January 1, 2008, but the tax generallywill be imposed on gross 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.

**Critical Accounting Policies**

The financial statementsof the Trust are prepared on the following basis:

(a)          Royaltyincome is recorded when received, including the effect of overtaken orundertaken positions and negative or positive adjustments, by the CorporateTrustee on the last business day of each calendar quarter. In addition, Royaltyincome includes amounts related to funds deposited or released from the SpecialCost Escrow account—see (c); and

(b)         Trustgeneral and administrative expenses are recorded when paid, except for the cashreserved for future general and administrative expenses; and

(c)          Thefunds deposited or released from the Special Cost Escrow account are recordedat the time of payment or receipt. The Special Cost Escrow account is anaccount of the Working Interest Owners and is not reflected in the financialstatements of the Trust.

This manner of reportingincome and expenses is considered to be the most meaningful because thequarterly distributions to Unit holders are based on net cash receipts receivedfrom the Working Interest Owners. The financial statements of the Trust differfrom financial statements prepared in accordance with generally acceptedaccounting principles, because, under such principles, Royalty income and Trustgeneral and administrative expenses for a quarter would be recognized on anaccrual basis. In addition, amortization of the net overriding royaltyinterest, calculated on a units-of-production basis, is charged directly toTrust corpus since such amount 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 June 30, 2006 and 2005**

There were nodistributions to the Unit holders for the three months ended June 30, 2006as compared to  $1,664,525, or $.350315per Unit, for the same period in 2005. There was no distributable income forthe second quarter of 2006 primarily as a result of damages caused to theRoyalty Properties by Hurricanes Rita and Katrina discussed below in “—OperationalReview” and a required deposit to the Special Cost Escrow account.  As a result of such events,  the Corporate Trustee does not expect thereto be any cash income distributions during 2006 and potentially during aportion or all of 2007.

Crude oil and condensaterevenues decreased $2,580,587, or 32%, to $5,400,972 in the second quarter of2006 as compared to $7,981,559 in the second quarter of 2005, due to a 48%decrease in crude oil and condensate volume to 89,309 barrels in the secondquarter of 2006 from 172,778 barrels in the second quarter of 2005. Thedecrease is partially offset by a 31% increase in the average price of crudeoil and condensate to $60.47 per barrel in the second quarter of 2006 from$46.20 per barrel in the second quarter of 2005.

Gas revenues decreased$3,351,929, or 99%, to $23,169 in the second quarter of 2006 from $3,375,098 inthe second quarter of 2005, due to an decrease in gas volumes of 99% to 2,654Mcf in the second quarter of 2006 from 503,949 Mcf in the second quarter of2005, offset by a 30% increase in the average price received for natural gas to$8.73 per Mcf in the second quarter of 2006 from $6.70 per Mcf in the secondquarter of 2005. Gas products revenue decreased $359,970, or 99%, to $2,216 inthe second quarter of 2006 from $362,186 in the second quarter of 2005, dueprimarily to a decrease in production volume of 467,473 gallons, or 99%, to2,478 gallons in the second quarter of 2006 from 469,951 gallons in the secondquarter of 2005.

The Trust’s share ofcapital expenditures increased $4,932,218, from $722,191 in the second quarterof 2005 to $5,654,409 in the second quarter of 2006. The increase in capitalexpenditures for the second quarter of 2006 related primarily to damages causedby Hurricanes Rita and Katrina.

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The Trust did not haveundistributed net income in the second quarter of 2006.

In the second quarter of2005, there was a net deposit of funds into the Special Cost Escrow account.The Trust’s share of the funds deposited during this quarter was $384,753

In the second 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 $16,028. As of June 30,2006, $6,496,132 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 informationrelating to the Special Cost Escrow, see “—Special Cost Escrow Account”, below.

**Six Months Ended June 30, 2006 and 2005**

There were nodistributions to the Unit holders for the six months ended June 30, 2006as compared to $1,980,960, or $0.4169129 per Unit, for the six months endedJune 30, 2005. The decrease in distributable income during 2006 resultedprimarily to damages caused to the Royalty Properties by Hurricanes Rita andKatrina and required deposits to the Special Cost Escrow account.

Crude oil and condensaterevenues decreased $5,314,356, or 33%, to $11,038,148 in the first six monthsof 2006 as compared to $16,352,504 for the same period in 2005, due to damagescaused by Hurricanes Rita and Katrina, which was partially offset by anincrease in the average price of Crude oil and condensate from $45.35 perbarrel to $58.43 per barrel during these periods.

Gas revenues decreased$6,285,752, or 92%, to $583,301 in the first six months of 2006 from $6,869,053for the same period in 2005, due to a 2% decrease in the average price receivedfor natural gas to $6.72 per Mcf in the first six months of 2006 from $6.89 perMcf in the same period of 2005, in addition to a decrease in gas volumes of 91%to 107,415 Mcf in the first six months of 2006 from 1,146,013 Mcf for the sameperiod in 2005. Gas products revenue decreased $716,795, or 86%, to $112,108 inthe first six months of 2006 from $828,903 in the same period of 2005,primarily due to a decrease in production volume of 894,233 gallons, or 86%, to144,262 gallons in the first six months of 2006 from 1,038,495 gallons in thesame period of 2005.

The Trust’s share ofcapital expenditures increased $5,387,071, from $1,994,905 in the first sixmonths of 2005 to $7,381,976 in the same period of 2006. The increase incapital expenditures for the first six months of 2006 related primarily todamages caused by Hurricanes Rita and Katrina.

The Trust did not haveundistributed net income in the first six months of 2006. 

In the first six months of2006, there was a net deposit of funds into the Special Cost Escrow account.The Trust’s share of the net funds deposited was $892,028. In the first sixmonths of 2005, there was a net deposit of funds into the Special Cost Escrowaccount. The Trust’s share of the net funds deposited was $2,325,747.  As of June 30, 2006, $6,496,132 remainedin the Special Cost Escrow account. The Special Cost Escrow is set aside forestimated abandonment costs and future capital expenditures, as provided for inthe Conveyance. For additional information relating to the Special Cost Escrow,see “—Special Cost Escrow Account”, below.

**Reserve for Future Trust 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 $1,512,997. During the 

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secondquarter of 2006, the Trust used $188,829 from the Trust’s cash reserve accountto pay the Trust’s general and administrative expenses when insufficientRoyalty income was received by the Trust, reducing the reserve amount held bythe Trust to $1,010,984 as of June 30, 2006. The reserve amount at June 30, 2005was $1,461,779. Amounts will be withheld to increase this reserve to itscalculated balance when 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**

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

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 of Chevron oil-equivalent production in the Gulf of Mexicoremained shut in due to damages from hurricanes in the third quarter. The timeit will take to resume this production is uncertain, and some of the volumesmay not be sufficiently economic to restore. The 2006 impact to the Trustproperties is estimated to be a 68% reduction in production as compared topre-hurricane volumes during 2005. Eugene Island 339 remains shut-in, butproduction is currently expected to resume at the end of 2006 after a new salespoint is built by the operator to replace the Eugene Island 338 sales point destroyedby Hurricane Rita, and assuming transportation availability is fully restoredon a third party transmission pipeline that incurred significant hurricane-relateddamages. The operator of this pipeline has advised that the hurricane-relateddamages on their pipeline are more extensive than previously thought, and theWorking Interest Owner has advised the Trustee that it is currently evaluatingvarious alternatives for transporation as production is also restored. TheWorking Interest Owner has also advised the Trust that it is working on aproject to compress and re-inject gas to the B-5 well, which would allowthe operator to increase oil production and to limit flaring of gas. On ShipShoal 182/183, gas production remaines shut in due to the Tennessee Gaspipeline being down. Major repairs are expected to be completed in early August andfull production is expected to resume in 4Q06. On West Cameron 643, productionhas remained shut in since September 2005 following Hurricane Rita’s majordamage to various platforms, but repairs are close to completion and gasproduction on this field is expected to resume mid-2006.

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

Ship Shoal 182/183 crudeoil revenues decreased from $3,846,974 in the second quarter of 2005 to$3,632,946 in the second quarter of 2006, primarily due to a decrease in netcrude oil production from 79,934 barrels in the second quarter of 2005 to59,190 barrels in the second quarter of 2006. The decrease was partially offsetby an increase in the average crude oil price from $48.13 per barrel in thesecond quarter of 2005 to $61.38 per barrel for the same period in 2006. Gasrevenues decreased from $1,434,114 in the second quarter of 2005 to $0 in thesecond quarter of 2006 due to damages caused by Hurricanes Rita and Katrinathat caused gas production to decrease from 212,176 Mcf in the second quarterof 2005 to 0 Mcf in the second quarter of 2006. Capital expenditures increasedfrom $502,888 in the second quarter 

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of 2005to $4,050,969 in the second quarter of 2006 primarily due to repair and upgradework on the platforms associated with damages caused by Hurricanes Rita andKatrina. Operating expenses increased from $360,372 in the second quarter of2005 to $472,293 for the same period in 2006.

Eugene Island 339 netcrude oil revenues decreased from $4,057,493 in the second quarter of 2005 to$1,648,164 for the same period in 2006 due to a decrease in volumes from 91,480barrels in the second quarter of 2005 to 28,130 barrels in the second quarterof 2006. In addition, the average crude oil price increased from $44.35 perbarrel in the second quarter of 2005 to $58.59 per barrel in the second quarterof 2006. Gas revenues decreased from $1,657,935 in the second quarter of 2005to $0 in the second quarter of 2006 due to damages caused by Hurricanes Ritaand Katrina that caused gas production to decrease from 241,059 Mcf in thesecond quarter of 2005 to 0 Mcf in the second quarter of 2006. Capitalexpenditures increased from $154,062 in the second quarter of 2005 to$1,602,231 in the second quarter of 2006 primarily due to repairs associatedwith hurricane-related damages. Operating expenses increased from $322,497 inthe second quarter of 2005 to $369,461 in the second quarter of 2006.

West Cameron 643 gasrevenues decreased from $351,773 in the second quarter of 2005 to $0 in thesecond quarter of 2006 due to damages caused by Hurricanes Rita and Katrinathat caused gas production to decrease from 65,640 Mcf in the second quarter of2005 to 0 Mcf in the second quarter of 2006. Operating expenses decreased from$897,638 in the second quarter of 2005 to $48,892 for the same period in 2006,and capital expenditures decreased from $52,058 in the second quarter of 2005to $1 for the same period in 2006.

East Cameron 371/381 crudeoil revenues changed from ($43,572) in the second quarter of 2005 to $0 in thesecond quarter of 2006, primarily due to a reversal of $44,201 for East Cameron381 block wells during the 2005 period. Gas revenues changed from ($101,385)for the second quarter of 2005 to $0 for the same period in 2006, primarily dueto a reversal of $111,676 from East Cameron 381 block wells during the 2005period. Capital expenditures were ($1,562) in the second quarter of 2005 andwere $0 for the same period in 2006. Operating expenses were ($31,631) in thesecond quarter of 2005 and were $4,168 for the same period in 2006.

**Six Months Ended June 30, 2006 and 2005**

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

Ship Shoal 182/183 crude oilrevenues increased from $8,098,608 in the first six months of 2005 to$8,229,579 in the same period in 2006, partially offset by a decrease in netcrude oil production from 171,290 barrels in the first six months of 2005 to135,746 in the same period of 2006. The decrease was partially offset by anincrease in the average crude oil price from $47.28 per barrel in the first sixmonths of 2005 to $60.92 per barrel for the same period in 2006. Gas revenuesdecreased from $3,062,086 in the first six months of 2005 to $0 in the sameperiod of 2006. Gas production decreased from 442,465 Mcf in the first sixmonths of 2005 to 0 Mcf in the same period of 2006 due to hurricane-relateddamages. There were no natural gas sales and thus no average sales price in thefirst six months of 2006 compared to $6.92 per Mcf for the same period in 2005due to hurricane-related damages. Capital expenditures increased from$1,160,773  in the first six months of2005 to $4,769,031 in the same period of 2006 primarily due tohurricane-related repairs. Operating expenses increased from $670,279  in the first six months of 2005 to $1,011,352for the same period in 2006.

Eugene Island 339 netcrude oil revenues decreased from $8,052,792 in the first six months of 2005 to$2,589,854 for the same period in 2006, due to a decrease in volumes from185,212 barrels in the first six months of 2005 to 49,429 barrels in the firstsix months of 2006. The average crude oil prices increased from $43.48 perbarrel in the first six months of 2005 to $52.40 per barrel for the same periodin 2006. Gas revenues decreased from $3,177,076 in the first six months 2005 to$547,819 for the same period in 2006, primarily due to a decrease in naturalgas volumes from 452,617 Mcf in the first six months of 2005 to 

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83,101Mcf for the same period in 2006. Capital expenditures increased from $743,119in the first six months of 2005 to $2,565,014 in the same period in 2006, dueto hurricane-related damages. Operating expenses decreased from $659,605 in thefirst six months of 2005 to $576,198 in the same period in 2006.

West Cameron 643 gasrevenues decreased from $648,379 in the first six months of 2005 to $0 for theperiod in 2006. This is due to a decrease in gas volumes from 110,413 Mcf inthe first six months of 2005 to 0 Mcf for the same period in 2006. Operatingexpenses decreased from $1,052,564 for the first six months of 2005 to $217,908for the same period in 2006, and capital expenditures decreased from $53,092for the first six months of 2005 to $46,156 for the same period in 2006.

East Cameron 371/381 crudeoil revenues were ($42,567) in the first six months of 2005 and $0 for the sameperiod in 2006. Gas revenues were ($90,615) for the first six months of 2005and $0 for the same period in 2006. Capital expenditures were ($1,561) in thefirst six months of 2005 and were $0 for the same period in 2006. Operatingexpenses were ($19,619)  in the first sixmonths of 2005 and were $8,201 for the same period in 2006. The 2005 decreasesfor East Cameron 371/381 are due to the Working Interest Owner includingproduction and expenses in previous quarters related to the EastCameron 381 block wells A-1 and A-3 in the Trust’s activityand the Trust not having an interest in these wells. The adjustments were madein the second quarter of 2005 to correct this error.

**Future Net Revenues and 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 are expectedto be received by the Trust during the next three years. In addition, becausethe 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 thoughsome or all of the Royalty Properties continued to have remaining productivelives. Upon termination of the Trust, the Trustees will sell for cash all ofthe assets held in the Trust estate and make a final distribution to Unitholders of any funds remaining after all Trust liabilities have been satisfied.The estimates of future net revenues discussed above are subject to largevariances from year to year and should not be construed as exact. There arenumerous 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 2005 Annual Report on Form 10-K.The Form 10-K is available at the SEC’s website *www.sec.gov*.

**Special Cost Escrow Account**

The Conveyance providesfor reserving funds for estimated future “Special Costs” of plugging andabandoning wells, dismantling platforms and other costs of abandoning theRoyalty Properties, as well as for the estimated amount of future drillingprojects and other capital expenditures on the Royalty Properties. As providedin the Conveyance, the amount of funds to be reserved is determined based onfactors including estimates of aggregate future production costs, aggregatefuture Special Costs, aggregate future net revenues and actual current netproceeds. Deposits into this account reduce current 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. 

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SpecialCost Escrow funds will generally be utilized to pay Special Costs to the extentthere are not adequate current net proceeds to pay such costs. Special Coststhat have been paid are no longer included in the Special Cost Escrowcalculation. Deposits to the Special Cost Escrow account will generally be madewhen the balance in the Special Cost Escrow account is less than 125% ofestimated future Special Costs and there is a Net Revenues Shortfall (a calculationof the excess of estimated future costs over estimated future net revenuespursuant to a formula contained in the Conveyance). When there is not a NetRevenues Shortfall, amounts in the Special Cost Escrow account will generallybe released, to the extent that Special Costs have been incurred. Amounts inthe Special Cost Escrow account generally will also be released when thebalance in such account exceeds 125% of estimated future Special Costs. In thefirst six months of 2006, there was a net deposit of funds to the Special CostEscrow account of $880,000. In the first six months of 2005, there was a netdeposit of funds to the Special Cost Escrow account of $2,325,747.

As of June 30, 2006,$6,496,132 remained in the Special Cost Escrow account.

Chevron, in its capacityas Managing 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.

**Overview of Production, Prices and Royalty Income**

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 and November.

| ** **                                                   | ** ** | **Royalty Properties  Three Months Ended  June 30,(1)** | ** ** |
|--------------------------------------------------------------|------------|-----------------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2006**                                                                    | ** ** | **2005** | ** ** |
| Crude oil and  condensate (bbls)                             |       | 89,309                                                                      |       | 172,778 |   |
| Natural gas and  gas products (Mcfe)                         |       | 3,008                                                                       |       | 571,084 |   |
| Crude oil and  condensate average price, per bbl             |       | $                                                                           | 60.47      |   | $ | 46.20 |   |
| Natural gas  average price, per Mcf (excluding gas products) |       | $                                                                           | 8.73       |   | $ | 6.70 |   |
| Crude oil and  condensate revenues                           |       | $                                                                           | 5,400,972  |   | $ | 7,981,559 |   |
| Natural gas and  gas products revenues                       |       | 25,385                                                                      |       | 3,737,284 |   |
| Production  expenses                                         |       | (1,271,653                                                                  | )          | (1,979,820 | ) |
| Capital  expenditures                                        |       | (5,654,409                                                                  | )          | (722,191 | ) |
| Undistributed net  loss (income)(2)                          |       | 1,515,733                                                                   |       | 0 |   |
| Refund of  (provision for) Special Cost Escrow               |       | (16,028                                                                     | )          | (1,435,154 | ) |
| **Net  Proceeds**                                            |       | $                                                                           | —     |   | $ | 7,581,678 |   |
| Royalty interest                                             |       | x25                                                                         | %          | x25 | % |
| Partnership share                                            |       | $                                                                           | —     |   | $ | 1,895,420 |   |
| Trust interest                                               |       | x99.99                                                                      | %          | x99.99 | % |
| Trust share of Royalty  Income                               |       | $                                                                           | —     |   | $ | 1,895,230 |   |

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(1)        Amounts represent actual production for the three-month period endedApril of each year respectively.

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(2)        Undistributed net loss represents negative NetProceeds generated during the respective period. An undistributed net loss iscarried forward and offset, in future periods, by positive Net Proceeds earnedby the related Working Interest Owner(s). Undistributed net income representspositive Net Proceeds, generated during the respective period, that wereapplied to an existing loss carryforward. As of June 30, 2006, the losscarryforward was $1,515,733. 

| ** **                                                   | ** ** | **Royalty Properties  Six Months Ended  June 30,** | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2006**                                                               | ** ** | **2005** | ** ** |
| Crude oil and condensate  (bbls)                             |       | 188,917                                                                |       | 360,556 |   |
| Natural gas and gas  products (Mcfe)                         |       | 107,415                                                                |       | 1,146,013 |   |
| Crude oil and condensate  average price, per bbl             |       | $                                                                      | 58.43      |   | $ | 45.35 |   |
| Natural gas average  price, per Mcf (excluding gas products) |       | $                                                                      | 6.72       |   | $ | 6.89 |   |
| Crude oil and condensate  revenues                           |       | $                                                                      | 11,038,148 |   | $ | 16,352,504 |   |
| Natural gas and gas  products revenues                       |       | 695,409                                                                |       | 7,697,956 |   |
| Production expenses                                          |       | (2,480,389                                                             | )          | 3,241,179 |   |
| Capital expenditures                                         |       | (7,381,976                                                             | )          | (1,994,905 | ) |
| Undistributed net  income(1)                                 |       | 1,515,733                                                              |       | 0 |   |
| Refund of (provision for)  Special Cost Escrow               |       | (3,386,926                                                             | )          | 9,124,600 |   |
| **Net Proceeds**                                             |       | $                                                                      | —     |   | $ | 9,689,776 |   |
| Royalty interest                                             |       | x25                                                                    | %          | x25 | % |
| Partnership share                                            |       | $                                                                      | —     |   | $ | 2,422,444 |   |
| Trust interest                                               |       | x99.99                                                                 | %          | x99.99 | % |
| Trust share of Royalty  Income                               |       | $                                                                      | —     |   | $ | 2,422,202 |   |

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(1)        Undistributed net loss represents negative NetProceeds generated during the respective period. An undistributed net loss iscarried forward and offset, in future periods, by positive Net Proceeds earnedby the related Working Interest Owner(s). Undistributed net income representspositive Net Proceeds, generated during the respective period, that wereapplied to an existing loss carryforward. As of June 30, 2006, the losscarryforward was $1,515,733.

**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 Financial Statementsincluded in 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, is recorded, processed, summarizedand reported within the time periods specified in the SEC’s rules andregulations. Disclosure controls and procedures include controls and proceduresdesigned to ensure that information required to be disclosed by the Trust isaccumulated and communicated by Chevron, as the managing general partner of thePartnership, and the working interest owners to JPMorgan Chase Bank, N.A., asCorporate Trustee of the Trust, and its employees who participate in thepreparation of the Trust’s periodic reports as appropriate to allow timelydecisions regarding required disclosure.

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

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 managinggeneral partner of the Partnership, including information that is collectedfrom the Working Interest Owners, and (C) conclusions and reports regarding reserves bythe Trust’s independent reserve engineers. See Part I, Item 1A. “RiskFactors—None of the Trustees, the Trust nor its Unit holders control theoperation or development of the Royalty Properties and have litte influenceover operation or development” and “—The Trustee relies on the Working InterestOwners and managing general partner for information regarding the RoyaltyProperties” in the Trust’s Annual Report on Form 10-K for the yearended December 31, 2005, and “Note 5—Negative Adjustments” of thefinancial statements and “Management’s Discussion and Analysis of FinancialCondition and Results of Operations” relating to operating information on EastCameron 371/381 included in the Annual Report on Form 10-K for theyear ended December 31, 2005 for a description of certain risks relatingto these arrangements and reliance and applicable adjustments to operatinginformation when reported by the Working Interest Owners to the CorporateTrustee and recorded in the Trust’s results of operations.

*Changes in InternalControl Over Financial Reporting.**  *During the three months ended March 31,2006, 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.

**Part II—Other Information**

**Item 1A.**                RiskFactors.

There have not been any material changes from riskfactors previously disclosed in response to Item 1A to Part 1 of theTrust’s Annual Report on Form 10-K for the year ended December 31,2005.

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**Item 6.        Exhibits.**

(Asterisk indicatesexhibit previously filed with the Securities and Exchange Commission andincorporated herein by reference.) JPMorgan Chase Bank, N.A., was formerlyknown as The Chase Manhattan Bank and is successor by mergers to the originalname 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)               |
| 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) /  15(d)-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:                |   | JPMorgan Chase Bank, N.  A. Corporate Trustee |
|       | By:                | ** ** | /s/  MIKE ULRICH |
| ** ** | ** **         | ** ** | **Mike  Ulrich*Vice President*** |

 

Date: August 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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