**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 June 30, 2005

**or**

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

**CommissionFile Number: 0-6910**

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TEL OFFSHORE TRUST

(Exact Name of Registrantas Specified in its Charter)

| **Texas**                                                                                     | **76-6004064**                        |
|-----------------------------------------------------------------------------------------------|---------------------------------------|
| (State of  Incorporation,  or Organization)                                                   | (I.R.S. Employer  Identification No.) |
| **JPMorgan Chase Bank, N.A.  Institutional Trust Services  700 Lavaca Street  Austin, Texas** | **78701**                             |
| (Address of  Principal Executive Offices)                                                     | (Zip Code)                            |

 

Registrant’s TelephoneNumber, Including Area Code: **(512) 479-2562**

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 mark whetherthe registrant is an accelerated filer (as defined in Rule 12b-2 ofthe Securities Exchange Act of 1934). Yes o  No x

Indicate the number ofshares outstanding of each of the registrant’s classes of common stock, as ofthe latest practicable date.

Asof August 15, 2005—4,751,510 Units of Beneficial Interest in TEL OffshoreTrust.

 

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**PART I—FINANCIAL INFORMATION**

**Item 1.**                        FinancialStatements.

**TEL OFFSHORE TRUSTSTATEMENTS OF ASSETS, LIABILITIES ANDTRUST CORPUS(Unaudited)**
| ** **                                                                                                                                | ** ** | **  June 30,    2005** | ** ** | **  December 31,    2004** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------------|------------|
| **Assets**                                                                                                                                |       |                                            |       |                                                |       |   |   |
| Cash and cash  equivalents                                                                                                                |       | $                                               | 3,126,304  |                                                |       | $ | 3,811,210 |   |   |
| Net overriding  royalty interest in oil and gas properties, net of accumulated amortization  of $28,189,235 and $28,177,602, respectively |       | 78,420                                          |       |                                                | 90,053     |   |   |
| Total assets                                                                                                                              |       | $                                               | 3,204,724  |                                                |       | $ | 3,901,263 |   |   |
| **Liabilities and Trust Corpus**                                                                                                          |       |                                            |       |                                                |       |   |   |
| Distribution payable  to Unit holders                                                                                                     |       | $                                               | 1,664,525  |                                                |       | $ | 2,470,196 |   |   |
| Reserve for  future Trust expenses                                                                                                        |       | 1,461,779                                       |       |                                                | 1,341,014  |   |   |
| Commitments and  contingencies                                                                                                            |       |                                            |       |                                                |       |   |   |
| Trust corpus  (4,751,510 Units of beneficial interest authorized and outstanding)                                                         |       | 78,420                                          |       |                                                | 90,053     |   |   |
| Total liabilities and  Trust corpus                                                                                                       |       | $                                               | 3,204,724  |                                                |       | $ | 3,901,263 |   |   |

 

**STATEMENTS OFDISTRIBUTABLE INCOME(Unaudited)**
| ** **                                                | ** ** | **Three Months Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|-----------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                                | ** ** | **2005**                                        | ** ** | **2004**                                      | ** ** | **2005** | ** ** | **2004** | ** ** |
| Royalty income  (See Note 4)                              |       | $                                               | 1,895,230  |                                          | $          | 83,857 |   | $ | 2,422,202 |   | $ | 83,857 |   |
| Interest income                                           |       | 3,037                                           |       | 1,452                                         |       | 5,858 |   | 3,220 |   |
|                                                      |       | 1,898,267                                       |       | 85,309                                        |       | 2,428,060 |   | 87,077 |   |
| (Increase) decrease  in reserve for future Trust expenses |       | (51,859                                         | )          | 56,341                                        |       | (120,765 | ) | 199,139 |   |
| General and  administrative expenses                      |       | (181,883                                        | )          | (141,650                                      | )          | (326,335 | ) | (286,216 | ) |
| Distributable  income                                     |       | $                                               | 1,664,525  |                                          | $          | 0 |   | $ | 1,980,960 |   | $ | 0 |   |
| Distributions per Unit  (4,751,510 Units)                 |       | $                                               | .350315    |                                          | $          | .000000 |   | $ | .416912 |   | $ | .000000 |   |

 

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  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|--------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                       | ** ** | **2005**                                        | ** ** | **2004**                                      | ** ** | **2005** | ** ** | **2004** | ** ** |
| Trust corpus,  beginning of period               |       | $                                               | 87,452     |                                          | $          | 141,287 |   | $ | 90,053 |   | $ | 154,619 |   |
| Distributable  income                            |       | 1,664,525                                       |       | 0                                             |       | 1,980,960 |   | 0 |   |
| Distribution  payable to Unit holders            |       | (1,664,525                                      | )          | 0                                             |       | (1,980,960 | ) | 0 |   |
| Amortization of  net overriding royalty interest |       | (9,032                                          | )          | (16,686                                       | )          | (11,633 | ) | (30,018 | ) |
| Trust corpus, end of  period                     |       | $                                               | 78,420     |                                          | $          | 124,601 |   | $ | 78,420 |   | $ | 124,601 |   |

 

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

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**TEL OFFSHORE TRUSTNOTES TO FINANCIAL STATEMENTS(Unaudited)**

**Note 1—Trust Organization**

Tenneco Offshore Company, Inc. (“Tenneco Offshore”)created the TEL Offshore Trust (“Trust”) effective January 1, 1983,pursuant to the Plan of Dissolution (“Plan”) approved by Tenneco Offshore’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 overriding royaltyinterest (“Royalty”) equivalent to a 25% net profits interest in the oil andgas properties (the “Royalty Properties”) of Tenneco Exploration, Ltd. (“ExplorationI”) located offshore Louisiana to the Partnership and issuing certificatesevidencing units of beneficial interest in the Trust (“Units”) in liquidationand cancellation of Tenneco Offshore’s common 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.

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 

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Island 367 properties,respectively, on October 1, 1995 and also assumed PennzEnergy’sobligations under the Conveyance with respect 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 acquired Anadarko’sinterest in East Cameron 354 and assumed Anadarko’s obligations under theconveyance 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 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 

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643thereafter; PennzEnergy/Devon with respect to East Cameron 354, Eugene Island348, Eugene Island 367 and Eugene/Devon Island 208 for periods from October 30,1992 until October 1, 1995, and with respect to Eugene Island 348 andEugene Island 208 thereafter; TEPI with respect to West Cameron 643 and EastCameron 371/381 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).

**Note 2—Basis of Accounting**

The accompanying unaudited financial information hasbeen prepared by JPMorgan Chase Bank, N.A., (formerly known as The ChaseManhattan Bank and the successor by merger to the original name of the CorporateTrust, Texas Commerce Bank National Association) (“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 31,2004.

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; and

(b)          Trust general andadministrative expenses are recorded when paid, except for the cash reservedfor future general and administrative expenses, as discussed in Note 7.

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 change in the 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.

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The Trust reviews the net overriding royalty interestin oil and gas properties for possible impairment whenever events or circumstancesindicate the carrying amount of the asset may not be recoverable. If there isan indication of impairment, the Trust prepares an estimate of future cashflows (undiscounted and without interest charges) expected to result from theuse of the asset and its eventual disposition. If these cash flows are lessthan 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 (See 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.

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 Trustees, including the Corporate Trustee, have noauthority over, have not evaluated and make no statement concerning, theinternal control over financial reporting of the working interest owners.

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 reserve. TheSpecial 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.

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**Note 4—Distributions to Unit Holders**

In accordance with the provisions of the Trust Agreement,generally all Net Proceeds received by the Trust, net of Trust general andadministrative expenses and any cash reserves established for the payment ofcontingent or future obligations of the Trust, are distributed currently to theUnit holders. Such distributions are referred to as “distributable income.” Theamounts distributed are determined on a quarterly basis and are payable to Unitholders of record as of the last business day of each calendar quarter.However, cash distributions are made in January, April, July and October andinclude interest earned from the quarterly record date to the date ofdistribution.

During the quarter ended March 31,2004, a Working Interest Owner made certain negative adjustments to previouslyreported Net Proceeds (See Note 5). Due to these negative adjustments aswell as to significant capital expenditures incurred on the Royalty Properties,there was no Royalty income for the quarter. As a result of these negativeadjustments, the deficit balance to the Trust at March 31, 2004 resultedin a loss carryforward of $3,307,628. In the second quarter of 2004, NetProceeds were offset by the loss carryforward of $3,307,628 with a resultingloss carryforward balance of $0 at June 30, 2004. No distributable incomewas available to the Unit holders in the second quarter of 2004 since the Trustrecoups expenses being paid from the reserve for Trust expense that theTrustees have established for anticipated future expenses. During the quarterended September 30, 2004, the Trust resumed distributions as the reservefor Trust expenses had been funded.

**Note 5—Negative Adjustments**

During the quarterended March 31, 2004, a Working Interest Owner informed the Trust that ithad made errors in prior periods which resulted in prior period Net Proceedsbeing overstated. This Working Interest Owner, Chevron, which is also theManaging General Partner, has advised the Trust that these errors consisted of:

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

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

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

The Trust recorded theadjustments during the first quarter of 2004, which resulted in a losscarryforward of $3,307,628 as of March 31, 2004. In the second quarter of2004, Net Proceeds were offset by the loss carryforward of $3,307,628, with aresulting in no further loss carryforward.

**Note 6—Special Cost Escrow 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 

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expenditures on theRoyalty Properties. As provided in the Conveyance, the amount of funds to bereserved is determined based on certain factors, including estimates ofaggregate future production costs, aggregate future Special Costs, aggregatefuture net revenues and actual current net profits interest. Deposits into thisaccount reduce current distributions and are placed in an escrow account andinvested in short-term certificates of deposit. Such account is herein referredto as the “Special Cost Escrow” account. The Trust’s share of interestgenerated from the Special Cost Escrow account serves to reduce the Trust’sshare of allocated production costs. Special Cost Escrow funds will generallybe utilized to pay Special Costs to the extent there are not adequate currentnet profits interest to pay such costs. Special Costs that have been paid areno longer included in the Special Cost Escrow calculation. Deposits to theSpecial Cost Escrow account will generally be made when the balance in theSpecial Cost Escrow account is less than 125% of estimated future Special Costsand there is a Net Revenues Shortfall (a calculation of the excess of estimatedfuture costs over estimated future net revenues pursuant to a formula containedin the Conveyance). When there is not a Net Revenues Shortfall, amounts in theSpecial Cost Escrow account will generally be released, to the extent thatSpecial Costs have been incurred. Amounts in the Special Cost Escrow accountgenerally will also be released when the balance in such account exceeds 125%of estimated future Special Costs. In the first six months of 2005, the Trusthad a net deposit of funds to the Special Cost Escrow account of $2,325,747. Inthe first six months of 2004, there was a net release of funds to the Trustfrom the Special Cost Escrow account of $1,189,581. As of June 30, 2005,$7,716,557 remained in the Special Cost Escrow account. The funds held in theSpecial Cost Escrow account are not reflected in the financial statements ofthe 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 7—ReserveFor Future Trust Expenses**

The Trust made a determination in 1998 to maintain acash reserve equal to three times the average expenses of the Trust during eachof the past three years to provide for future administrative expenses inconnection with the winding up of the Trust. The reserve amount at June 30,2005 was $1,461,779. The reserve amount at December 31, 2004 was $1,341,014.

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**Item 2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations.

**Critical Accounting 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; and

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

(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 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.

**Financial Review**

**ThreeMonths Ended June 30, 2005 and 2004**

Distributions to the Unit holders for the six monthsended June 30, 2005 amounted to $1,664,525 or $.350315 per Unit ascompared to no distributions for the same period in 2004. The increase indistributable income for the second quarter of 2005 was primarily as a resultof negative adjustments to Net Proceeds and significant capital expendituresthat reduced Royalty income in the first and second quarters of 2004.

There were no distributions for the three months endedJune 30, 2004. The Trust was in a deficit position with Working InterestOwners as a result of negative adjustments to Net Proceeds relating to priorperiods. The negative adjustments made refer to downward adjustments to revenuesand production by Chevron based on improper credit to the Trust of revenues andproduction on Eugene Island 339. This improper credit related to productioncredited from wells in which the Trust has no interest from as early as June 2002through October 2003.

Crude oil and condensate revenues decreased$1,006,381, or 11%, to $7,981,559 in the second quarter of 2005 as compared to$8,987,940 in the second quarter of 2004, due to a 34% decrease in crude oiland condensate volume to 172,778 barrels in the second quarter of 2005 from263,463 barrels in the second quarter of 2004. The decrease is partially offsetby a 35% increase in the average price of crude oil and condensate to $46.20per barrel in the second quarter of 2005 from $34.11 per barrel in the secondquarter of 2004.

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Gas revenues decreased $1,427,314, or 30%, to$3,375,098 in the second quarter of 2005 from $4,802,412 in the second quarterof 2004, due to an decrease in gas volumes of 39% to 503,949 Mcf in the secondquarter of 2005 from 831,791 Mcf in the second quarter of 2004, offset by a 16%increase in the average price received for natural gas to $6.70 per Mcf in thesecond quarter of 2005 from $5.77 per Mcf in the second quarter of 2004. Gasproducts revenue decreased $406,200, or 53%, to $362,186 in the second quarterof 2005 from $768,386 in the second quarter of 2004, due primarily to adecrease in production volume of 918,621 gallons, or 66%, to 469,951 gallons inthe second quarter of 2005 from 1,388,572 gallons in the second quarter of2004.

The Trust’s share of capital expenditures increased$74,112, from $648,079 in the second quarter of 2004 to $722,191 in the secondquarter of 2005. The increase in capital expenditures for the second quarter of2005 related primarily to a generator engine replacement and equipment upgradeson Eugene Island 339 as well as a compressor and generator installation onShip Shoal 182/183.

The Trust did not have undistributed net income in thesecond quarter of 2005. The Trust’s share of undistributed net income was$13,231,454 in the second quarter of 2004. As discussed above, Net Proceedswere offset by the net loss carryforward of $3,307,628 during the secondquarter of 2004, with a resulting loss carryforward balance of $0 as of June 30,2004. In addition, Royalty income and interest income did not exceed Trustexpenses during the quarter, resulting in a use of funds from the reserve forTrust expenses. See “—Reserve for Future Trust Expenses” below.

In thesecond quarter of 2005, there was a net deposit of funds into the Special CostEscrow account. The Trust’s share of the net funds deposited was $384,753. Inthe second quarter of 2004, there was a refund of funds into the Special CostEscrow account. The Trust’s share of the funds refunded during this quarter was$336,232. As of June 30, 2005, $7,716,557 remained in the Special CostEscrow account. The Special Cost Escrow is set aside for estimated abandonmentcosts and future capital expenditures, as provided for in the Conveyance. Foradditional information relating to the Special Cost Escrow, see “—Special CostEscrow Account”, below.

**Six Months Ended June 30, 2005 and 2004**

Crude oil and condensate revenues increased$9,494,794, or 138%, to $16,352,504 in the first six months of 2005 as comparedto $6,857,710 for the same period in 2004, due to a 112% increase in crude oiland condensate volume to 360,556 barrels in the first six months of 2005 from170,383 barrels for the same period in 2004. The revenues and volumes for thefirst six months of 2004 include negative adjustments, as a result of theimproper credits of production and revenues by Chevron, totaling 295,224barrels recorded by the Trust in the first quarter of 2004. The average priceof crude oil and condensate increased from $28.50 per barrel in the first sixmonths of 2004 to $45.35 per barrel in the first six months of 2005.

Gas revenues increased $614,483, or 10%, to $6,869,053in the first six months of 2005 from $6,254,570 for the same period in 2004,due to a 16% increase in the average price received for natural gas to $6.89per Mcf in the first six months of 2005 from $5.96 per Mcf in the same periodof 2004, which was partially offset by a decrease in gas volumes of 7% to997,657 Mcf in the first six months of 2005 from 1,067,945 Mcf for the sameperiod in 2004. Gas products revenue increased $69,523, or 9%, to $828,903 inthe first six months of 2005 from $759,380 in the same period of 2004,partially offset due to a decrease in production volume of 325,148 gallons, or24%, to 1,038,495 gallons in the first six months of 2005 from 

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1,363,643 gallons in thesame period of 2004. The production for the first six months of 2004 includesnegative adjustments resulting from the improper credits of production andrevenues by Chevron.

The Trust’s share of capital expenditures decreased$12,532,373, from $14,527,278 in the first six months of 2004 to $1,994,905 inthe same period of 2005. The decrease in capital expenditures for the first sixmonths of 2005 related primarily to the drilling of the new I-4 well andsome residual costs from the completion of the I-2 and I-3 wells onthe Ship Shoal 182/183 property in the first quarter of 2004, compared tocapital expenditures for the same period in 2005 which were related to thepurchase of a compressor on the Ship Shoal 182/183 property and some residualcosts from well completions on Eugene Island 339. The Trust recorded an adjustmentof $2,026,684 in the first quarter of 2004 relating primarily to chargesincurred in the fourth quarter of 2003. Adjustments to capital expenditures arebased on miscalculations and duplication of downward adjustments allocations onShip Shoal 182/183 during the third and fourth quarters of 2003. Thesemiscalculations and duplications are reflected in the amounts provided.

The Trust did not have undistributed net income in thefirst six months of 2005. As discussed above, Net Proceeds during the secondquarter of 2004 were offset by the loss carryforward of $3,307,628 existing asof March 31, 2004, resulting in a loss carryforward balance of $0 at June 30,2004.

In the first six months of2005, there was a net deposit of funds into the Special Cost Escrow account.The Trust’s share of the net funds deposited was $2,325,747. In the first sixmonths of 2004, there was a net refund of funds into the Special Cost Escrowaccount. The Trust’s share of the funds deposited was $1,189,581. As of June 30,2005, $7,716,557 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.

**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 was sufficientat this time to provide for future administrative expenses in connection withthe winding up of the Trust. The reserve amount for December 31, 2004 was$1,341,014. The reserve amount for June 30, 2005 was $1,461,779.

**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.

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**Operational Review**

**ThreeMonths Ended June 30, 2005 and 2004**

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

Ship Shoal 182/183 crudeoil revenues decreased from $4,300,079 in the second quarter of 2004 to$3,846,974 in the second quarter of 2005, primarily due to a decrease in netcrude oil production from 123,819 barrels in the second quarter of 2004 to79,934 in the second quarter of 2005. The decrease was partially offset by anincrease in the average crude oil price from $34.73 per barrel in the secondquarter of 2004 to $48.13 per barrel for the same period in 2005. Gas revenuesdecreased from $3,361,078 in the second quarter of 2004 to $1,434,114 in thesecond quarter of 2005 due to a decrease in gas production from 578,282 Mcf inthe second quarter of 2004 to 212,176 Mcf in the second quarter of 2005, whichwas partially offset by an increase in the average natural gas sales price from$5.81 per Mcf in the second quarter of 2004 to $6.76 per Mcf for the sameperiod in 2005. The decrease in gas volume was primarily due to a 13-dayfield shut-in for additional repairs on past hurricane damage and materialproduction declines. Capital expenditures increased from $82,763 in the secondquarter of 2004 to $502,888 in the second quarter of 2005. Operating expensesdecreased from $746,914 in the second quarter of 2004 to $360,372 for the sameperiod in 2005.

Eugene Island 339 netcrude oil revenues decreased from $4,552,755 in the second quarter of 2004 to$4,057,493 for the same period in 2005 due to a decrease in volumes from135,791 in the second quarter of 2004 to 91,480 barrels in the second quarterof 2005. In addition, the average crude oil price increased from $33.53 perbarrel in the second quarter of 2004 to $44.35 per barrel in the second quarterof 2005. Gas revenues increased from $938,881 in the second quarter 2004 to$1,657,935 in the second quarter of 2005, primarily due to an increase innatural gas volumes from 152,687 Mcf in the second quarter of 2004 to 241,059Mcf in the second quarter of 2005. Capital expenditures decreased from $524,409in the second quarter of 2004 to $154,062 in the second quarter of 2005, due tovarious capital projects that were completed in the second quarter of 2004.Operating expenses decreased from $358,010 in the second quarter of 2004 to$322,497 in the second quarter of 2005.

West Cameron 643 gasrevenues decreased from $398,406 in the second quarter of 2004 to $351,773 inthe second quarter of 2005. This is due to a decrease in gas volumes from72,970 Mcf in the second quarter of 2004 to 65,640 Mcf for the same period in2005. The decrease in volumes was primarily due to diminishing returns fromwells. Gas prices decreased $0.10 per Mcf from $5.46 per Mcf in the secondquarter of 2004 to $5.36 per Mcf in the second quarter of 2005. Operatingexpenses increased from $84,993 in the second quarter of 2004 to $897,638 forthe same period in 2005, and capital expenditures increased from $2,066 in thesecond quarter of 2004 to $52,058 for the same period in 2005, due to expensesrelated to the A-14 well.

East Cameron 371/381 crudeoil revenues decreased from $9,205 in the second quarter of 2004 to ($43,572)in the second quarter of 2005, primarily due to a reversal of $44,201 (1,262bbls) from East Cameron 381 block wells. Gas revenues decreased from $28,230for the second quarter of 2004 to ($101,385) for the same period in 2005 due toreversal of $111,676 (21,656 Mcf) from East Cameron 381 block wells. Capitalexpenditures were $1,283 in the second quarter of 2004 and were ($1,562) forthe same period in 2005. Operating expenses were $11,109 in the second quarterof 2004 and were ($31,631) for the same period in 2005. The decreases for EastCameron 371/381 are due to the Working Interest Owner 

13

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includingproduction and expenses in previous quarters related to the East Cameron 381block wells A-1 and A-3 in the Trust’s activity and the Trust not having aninterest in these wells.  The adjustmentswere made in the second quarter of 2005 to correct this error.

**SixMonths Ended June 30, 2005 and 2004**

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

Duringthe first quarter of 2004, a Working Interest Owner informed the Trust that ithad made errors in prior periods which resulted in prior periods Net Proceedsbeing overstated. This Working Interest Owner, Chevron, which is also theManaging General Partner, has advised the Trust that these errors consisted of:

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

·       ShipShoal 182/183—a $1,336,287 gross adjustment to reverse revenues previouslycredited to the Trust primarily for double-counted production and a$1,855,976 adjustment to correct previously recorded adjustments to capitalexpenditures

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

The gross adjustments,before the Special Cost Escrow account adjustment, were $10,911,175 or a$2,727,521 increase in the losses to be carried forward and netted againstfuture Net Proceeds earned by the Trust on Royalty Properties operated by thisWorking Interest Owner.

Ship Shoal 182/183 crudeoil revenues increased from $6,707,654 in the first six months of 2004 to$8,098,608 in the same period in 2005, partially offset by a decrease in netcrude oil production from 203,234 barrels in the first six months of 2004 to171,290 in the same period of 2005, which includes a negative retroactiveadjustment of 44,214 barrels relating to the fourth quarter of 2003 discussedabove. The decrease was partially offset by an increase in the average crudeoil price from $32.52 per barrel in the first six months of 2004 to $47.28 perbarrel for the same period in 2005. Gas revenues decreased from $4,416,699 inthe first six months of 2004 to $3,062,086 in the same period of 2005. Gasproduction decreased from 761,149 Mcf in the first six months of 2004 to442,465 Mcf in the same period of 2005. In addition, the average natural gassales price increased from $5.79 per Mcf in the first six months of 2004 to$6.92 per Mcf for the same period in 2005. Capital expenditures decreased from$7,850,213 in the first six months of 2004 to $1,160,773 in the same period of2005. Operating expenses decreased from $1,707,003 in the first six months of2004 to $670,279 for the same period in 2005.

Eugene Island 339 netcrude oil revenues increased from $340,079 in the first six months of 2004 to$8,052,792 for the same period in 2005, due to an increase in volumes from(26,379) in the first six months of 2004 to 185,212 barrels in the first sixmonths of 2005, which gives effect to a negative retroactive adjustment of236,650 barrels relating to the period of January through October 2003for improper credits of production and revenues discussed above. The averagecrude oil prices increased from $29.75 per barrel in the first six months of2004 to $43.48 per barrel for the same period in 2005. Gas revenues increasedfrom $1,183,688 in the first six months 2004 to $3,177,076 for the same periodin 2005, primarily due to an increase in natural gas volumes from 181,711 Mcfin the first six months of 2004 to 452,617 Mcf for the 

14

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sameperiod in 2005, which gives effect to a negative retroactive adjustment of90,976 Mcf for improper credits of production and revenues discussed above.Capital expenditures decreased from $6,651,508 in the first six months of 2004to $743,119 in the same period in 2005, due to various capital projects thatwere completed in the first six months of 2004, including the C-20 and C-21drilling projects that cost approximately $1.5 and $3.3 million,respectively, and upgrades to the C platform facilities that cost approximately$517,000. Operating expenses decreased from $945,363 in the first six months of2004 to $659,605 in the same period in 2005.

West Cameron 643 gasrevenues increased from $478,488 in the first six months of 2004 to $648,379for the period in 2005. This is due to an increase in gas volumes from 90,803Mcf in the first six months of 2004 to 110,413 Mcf for the same period in 2005.Operating expenses increased from $154,144 for the first six months of 2004 to$1,052,564 for the same period in 2005, and capital expenditures increased from$2,581 for the first six months of 2004 to $53,092 for the same period in 2005due to production increases.

East Cameron 371/381 crudeoil revenues decreased from $18,054 in the first six months of 2004 to ($42,567)for the same period in 2005, primarily due to the decrease in crude oilproduction from 528 barrels in the first six months of 2004 to (1,227) barrelsfor the same period in 2005. Gas revenues decreased from $49,477 for the firstsix months of 2004 to ($90,615) for the same period in 2005. Capitalexpenditures were $1,323 in the first six months of 2004 and were ($1,561) forthe same period in 2005. Operating expenses were $17,071 in the first sixmonths of 2004 and were ($19,619) for the same period in 2005. The decreasesfor East Cameron 371/381 are due to the Working Interest Owner includingproduction and expenses in previous quarters related to the East Cameron 381block wells A-1 and A-3 in the Trust’s activity and the Trust nothaving an interest in these wells. The adjustments were made in the secondquarter of 2005 to correct this error.

**FutureNet 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, 2004 future netrevenues attributable to the Trust’s royalty interests were estimated at$30.2 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 in order to correspond withdistributions to the Trust. Such reserve study also indicates thatapproximately 75% 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 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 forcash all of the assets held in the Trust estate and make a final distributionto Unit 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 2004 Annual Report on Form 10-K.The Form 10-K is available upon request from the Corporate Trustee.

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**Special Cost Escrow Account**

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 profits interest. Deposits into this accountreduce current distributions and are placed in an escrow account and investedin short-term certificates of deposit. Such account is herein referred to asthe “Special Cost Escrow” account. The Trust’s share of interest generated fromthe Special Cost Escrow account serves to reduce the Trust’s share of allocatedproduction costs. Special Cost Escrow funds will generally be utilized to paySpecial Costs to the extent there are not adequate current net profits interestto 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 six months of 2005, there was anet deposit of funds to the Special Cost Escrow account of $2,325,747. In thefirst six months of 2004, there was a net release of funds from the SpecialCost Escrow account. The Trust’s share of funds released was $1,189,581. As of June 30,2005, $7,716,557 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, if made, could result in a significantreduction in Royalty income in the periods in which such deposits are made,including the possibility that no Royalty income would be received in suchperiods.

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**Overviewof 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 andNovember.
| ** **                                                      | ** ** | **Royalty Properties  Three Months Ended  June 30,** | ** ** |
|-----------------------------------------------------------------|------------|--------------------------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2005**                                                                 | ** ** | **2004** | ** ** |
| Crude oil and condensate  (bbls)(1)                             |       | 172,778                                                                  |       | 263,463 |   |
| Natural gas and gas  products (Mcf)(2)                          |       | 571,084                                                                  |       | 1,030,158 |   |
| Crude oil and condensate  average price, per bbl(1)             |       | $                                                                        | 46.20      |   | $ | 34.11 |   |
| Natural gas average  price, per Mcf (excluding gas products)(2) |       | $                                                                        | 6.70       |   | $ | 5.77 |   |
| Crude oil and condensate  revenues(1)                           |       | $                                                                        | 7,981,559  |   | $ | 8,987,940 |   |
| Natural gas and gas  products revenues(2)                       |       | 3,737,284                                                                |       | 5,570,798 |   |
| Production expenses(3)                                          |       | (1,979,820                                                               | )          | (1,707,784 | ) |
| Capital expenditures(3)                                         |       | (722,191                                                                 | )          | (648,079 | ) |
| Undistributed net loss  (income)(4)                             |       | 0                                                                        |       | (13,231,454 | ) |
| (Deposit) refund of  escrowed special costs                     |       | (1,435,154                                                               | )          | 1,344,040 |   |
| **Net Proceeds**                                                |       | $                                                                        | 7,581,678  |   | $ | 335,461 |   |
| Royalty interest                                                |       | x25                                                                      | %          | x25 | % |
| Partnership share                                               |       | $                                                                        | 1,895,420  |   | $ | 83,865 |   |
| Trust interest                                                  |       | x99.99                                                                   | %          | x99.99 | % |
| Trust share                                                     |       | $                                                                        | 1,895,230  |   | $ | 83,857 |   |

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(1)          Includes negative volumeadjustments of 1,262 bbls for the three months ended June 30, 2005.Exclusive of these adjustments, volumes would have been 174,040 bbls.Excluding the impact of these adjustments, crude oil and condensate averageprice per bbl would have been $46.11. Excluding the impact of these adjustments,crude oil and condensate revenues would have been $8,025,760.

(2)   Includespositive volume adjustments of 5,054 Mcf for the three months endedJune 30, 2005. Exclusive of these adjustments natural gas volumes wouldhave been 498,895 Mcf. Excluding the impact of these adjustments naturalgas average price per Mcf would have been $6.78 and natural gas and gas liquidsrevenue would have been $3,746,721.

(3)   Includespositive adjustments of production expenses and capital expenditures for thethree months ended June 30, 2005 of $39,348 and $1,562, respectively.Excluding the impact of these adjustments production expense would have been$2,019,168 and capital expenditures would have been $723,753.

(4)          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 was applied to an existing loss carryforward.In the quarter ended June 30, 2004, Net Proceeds were offset by the losscarryforward of $3,307,628 existing as of March 31, 2004. At June 30,2004, there was no additional loss carryforward.

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| ** **                                                      | ** ** | **Royalty Properties  Six Months Ended  June 30,** | ** ** |
|-----------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2005**                                                               | ** ** | **2004** | ** ** |
| Crude oil and condensate  (bbls)(1)                             |       | 360,556                                                                |       | 170,383 |   |
| Natural gas and gas  products (Mcf)(2)                          |       | 1,146,013                                                              |       | 1,262,751 |   |
| Crude oil and condensate  average price, per bbl(1)             |       | $                                                                      | 45.35      |   | $ | 28.50 |   |
| Natural gas average  price, per Mcf (excluding gas products)(2) |       | $                                                                      | 6.89       |   | $ | 5.96 |   |
| Crude oil and condensate  revenues(1)                           |       | $                                                                      | 16,352,504 |   | $ | 6,857,710 |   |
| Natural gas and gas  products revenues(2)                       |       | 7,697,956                                                              |       | 7,013,950 |   |
| Production expenses(3)                                          |       | $                                                                      | 3,241,179  |   | (3,792,477 | ) |
| Capital expenditures(3)                                         |       | (1,994,905                                                             | )          | (14,527,278 | ) |
| Undistributed net  income(4)                                    |       | 0                                                                      |       | (1,356,586 | ) |
| Refund of escrowed  special costs                               |       | 9,124,600                                                              |       | 6,140,140 |   |
| **Net Proceeds**                                                |       | $                                                                      | 9,689,776  |   | $ | 335,459 |   |
| Royalty interest                                                |       | x25                                                                    | %          | x25 | % |
| Partnership share                                               |       | $                                                                      | 2,422,444  |   | $ | 83,865 |   |
| Trust interest                                                  |       | x99.99                                                                 | %          | x99.99 | % |
| Trust share                                                     |       | $                                                                      | 2,422,202  |   | $ | 83,857 |   |

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(1)   Includesnegative volume adjustments of 295,224 bbls for the six months ended June 30,2004. Exclusive of these adjustments, volumes would have been 465,607 bbls.Excluding the impact of these adjustments crude oil and condensate averageprice per bbl would have been $32.15. Excluding the impact of these adjustmentscrude oil and condensate revenues would have been $15,090,081.

(2)          Includes negative volumeadjustments of 45,954 Mcf for the six months ended June 30, 2004.Exclusive of these adjustments volumes would have been 1,341,173 Mcf. Excludingthe impact of these adjustments natural gas average price per Mcf would havebeen $5.82 and natural gas and natural gas liquids revenue would have been$9,010,425.

(3)          Includes negativeadjustments of $2,538,232 for the six months ended June 30, 2004. Excludingthe impact of these adjustments production expense would have been $2,696,311and capital expenditures would have been $12,145,463.

(4)          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 was applied to an existing loss carryforward.In the quarter ended June 30, 2004, Net Proceeds were offset by the losscarryforward of $3,307,628 existing as of March 31, 2004. At June 30,2004, there was no additional loss carryforward.

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

No material changes haveoccurred since our Annual Report on Form 10-K for the year-ended December 31,2004. Reference is also made to Note 2 of the Notes to FinancialStatements included in Item 1 of this Form 10-Q.

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**Item 4.**                        Controlsand Procedures.

(a)   *Evaluation of disclosure controls and procedures.*

TheCorporate Trustee maintains disclosure controls and procedures designedto ensure that information required to be disclosed by the Trust in the reportsthat it files or submits under the Exchange Act of 1934, as amended, isrecorded, processed, summarized and reported within the time periods specifiedin the SEC’s rules and regulations. Disclosure controls and proceduresinclude controls and procedures designed to ensure that information required tobe disclosed by the Trust is accumulated and communicated by Chevron, as themanaging general partner of the Partnership, and the working interest owners toJPMorgan Chase Bank, N.A., as Corporate Trustee of the Trust, and its employeeswho participate in the preparation of the Trust’s periodic reports asappropriate to allow timely decisions regarding required disclosure.

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

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 by theWorking Interest Owners, including historical operating data, plans for futureoperating 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 bythe Trust’s independent reserve engineers. See Item 1 “Business—Principal Trust 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” inthe Trust’s Form 10-K, and “Note 5—Negative Adjustments” of the financial statementsand “Management’s Discussion and Analysis of Financial Condition and Results ofOperating” relating to operating information on East Cameron 371/381 includedin this Form 10-Q, for a description of certain risks relating to thesearrangements and reliance and applicable adjustments to operating informationwhen reported by the Working Interest Owners to the Corporate Trustee andrecorded in the Trust’s results of operations. 

*Changes in Internal Control OverFinancial Reporting.  *In connection with the evaluationby the Corporate Trustee of changes in internal control over financialreporting of the Trust that occurred during the Trust’s last fiscal quarter, nochange in the Trust’s internal control over financial reporting was identified thathas materially affected, or is reasonably likely to materially affect, theCorporate Trustee’s internal control over financial reporting relating to theTrust. The Corporate Trustee notes for purposes of clarification that it has noauthority over, has not evaluated and makes 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—OTHER INFORMATION**

**Item 6.**                        Exhibits.

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

 

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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,thereunto duly authorized.
|                             | TEL OFFSHORE TRUST |
|-----------------------------|--------------------|
|                        | By:                | JPMORGAN CHASE  BANK, N.A., |
|                        |               | Corporate Trustee |
|                        | By:                | /s/  MIKE ULRICH |
|                        |               | **Mike  Ulrich** |
|                        |               | ***Vice  President*** |
| Date: August 15,  2005 |               |   |

 

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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