**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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**FORM 10-Q**

x                              QuarterlyReport Pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934 for the quarterly period ended September 30, 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,              |   | (I.R.S. Employer     |
| or Organization)                       |   | Identification  No.) |
| **JPMorgan Chase Bank, N.A., Trustee** |   | ** **           |
| **Institutional  Trust Services**      |   | ** **           |
| **700  Lavaca Street**                 |   | ** **           |
| **Austin,  Texas**                     |   | **78701**            |
| (Address of  Principal                 |   | (Zip Code)           |
| Executive  Offices)                    |   |                 |

 

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

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

Indicate by check markwhether the registrant is an accelerated filer (as defined in Rule 12b-2of the Securities Exchange Act of 1934). Yes* *o * *No þ

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of the SecuritiesExchange Act of 1934). o  Yes þ  No

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

As of November 14,2005—4,751,510 Units of Beneficial Interest in TEL Offshore Trust.

 

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**PART I—FINANCIAL INFORMATION**

**Item 1.**                        FinancialStatements.

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

| ** **                                                                                                                                      | ** ** | **September 30,    2005** | ** ** | **December 31,    2004** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------|------------|-----------------------------------------|------------|
| **Assets**                                                                                                                                      |       |                                     |       |                                    |       |   |   |
| Cash and cash  equivalents                                                                                                                      |       | $                                        | 6,890,148  |                                    |       | $ | 3,811,210 |   |   |
| Net overriding  royalty interest in oil and gas properties, net of accumulated amortization  of $28,198,383 and $28,177,602,  respectively |       | 69,272                                   |       |                                    | 90,053     |   |   |
| Total assets                                                                                                                                    |       | $                                        | 6,959,420  |                                    |       | $ | 3,901,263 |   |   |
| **Liabilities  and Trust Corpus**                                                                                                               |       |                                     |       |                                    |       |   |   |
| Distribution  payable to Unit holders                                                                                                           |       | $                                        | 5,447,639  |                                    |       | $ | 2,470,196 |   |   |
| Reserve for  future Trust expenses                                                                                                              |       | 1,442,509                                |       |                                    | 1,341,014  |   |   |
| Commitments and  contingencies                                                                                                                  |       |                                     |       |                                    |       |   |   |
| Trust corpus  (4,751,510 Units of beneficial interest authorized and outstanding)                                                               |       | 69,272                                   |       |                                    | 90,053     |   |   |
| Total liabilities and  Trust corpus                                                                                                             |       | $                                        | 6,959,420  |                                    |       | $ | 3,901,263 |   |   |

 

**STATEMENTS OFDISTRIBUTABLE INCOME(Unaudited)**

| ** **                                                | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-----------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| Royalty income                                            |       | $                                                    | 5,591,822  |                                                | $          | 3,316,095 |   | $ | 8,014,024 |   | $ | 3,399,952 |   |
| Interest income                                           |       | 3,850                                                |       | 1,819                                               |       | 9,708 |   | 5,039 |   |
|                                                      |       | 5,595,672                                            |       | 3,317,914                                           |       | 8,023,732 |   | 3,404,991 |   |
| Decrease/(Increase) in reserve for future Trust  expenses |       | 19,270                                               |       | (347,290                                            | )          | (101,495 | ) | (148,151 | ) |
| General and  administrative expenses                      |       | (167,303                                             | )          | (96,613                                             | )          | (493,638 | ) | (382,829 | ) |
| Distributable  income                                     |       | $                                                    | 5,447,639  |                                                | $          | 2,874,011 |   | $ | 7,428,599 |   | $ | 2,874,011 |   |
| Distributions per Unit  (4,751,510 Units)                 |       | $                                                    | 1.146507   |                                                | $          | .604863 |   | $ | 1.563419 |   | $ | .604863 |   |

 

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

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

| ** **                                       | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|--------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                       | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| Trust corpus,  beginning of period               |       | $                                                    | 78,420     |                                                | $          | 124,601 |   | $ | 90,053 |   | $ | 154,619 |   |
| Distributable  income                            |       | 5,447,639                                            |       | 2,874,011                                           |       | 7,428,599 |   | 2,874,011 |   |
| Distribution  payable to Unit holders            |       | (5,447,639                                           | )          | (2,874,011                                          | )          | (7,428,599 | ) | (2,874,011 | ) |
| Amortization of  net overriding royalty interest |       | (9,148                                               | )          | (13,140                                             | )          | (20,781 | ) | (43,158 | ) |
| Trust corpus, end of  period                     |       | $                                                    | 69,272     |                                                | $          | 111,461 |   | $ | 69,272 |   | $ | 111,461 |   |

 

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

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**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 overridingroyalty interest (“Royalty”) equivalent to a 25% net profits interest in theoil and gas properties (the “Royalty Properties”) of Tenneco Exploration, Ltd.(“Exploration I”) located offshore Louisiana to the Partnership and issuingcertificates evidencing units of beneficial interest in the Trust (“Units”) inliquidation and 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 Tenneco subjectto the Royalty. Tenneco, who was then serving as the Managing General Partnerof the Partnership, assumed the obligations of Exploration I, including itsobligations under the instrument conveying the Royalty to the Partnership (the “Conveyance”).The dissolution of Exploration I had no impact on future cash distributions toholders 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 from Chevron.The Royalty Properties acquired by Texaco were West Cameron 643 and EastCameron 371/381. As a result of such acquisitions, TEPI replaced Chevron as theWorking Interest Owner of such properties on December 1, 1994. TEPI alsoassumed Chevron’s obligations under the Conveyance with respect to theseproperties.

On October 1, 1995, SONAT Exploration Company (“SONAT”)acquired the East Cameron 354 property from PennzEnergy. In addition, on October 1,1995, Amoco Production Company (“Amoco”) acquired the Eugene Island 367property from PennzEnergy. As a result of such acquisitions, SONAT and Amocoreplaced PennzEnergy as the Working Interest Owners of the East Cameron 354 andEugene Island 367 properties, respectively, on October 1, 1995 and alsoassumed PennzEnergy’s obligations under the Conveyance with respect to theseproperties.

Effective January 1, 1998, Energy ResourceTechnology, Inc. (“ERT”) acquired the East Cameron 354 property fromSONAT. As a result of such acquisition, ERT replaced SONAT as the WorkingInterest Owner of the East Cameron 354 property effective January 1, 1998,and also assumed 

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SONAT’s obligations underthe Conveyance with respect to such property. In October 1998, AmeradaHess Corporation (“Amerada”) acquired the East Cameron 354 property from ERTeffective January 1, 1998. As a result of such acquisition, Ameradareplaced ERT as the Working Interest Owner of the East Cameron 354 propertyeffective January 1, 1998, and also assumed ERT’s obligations under theConveyance 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 an Agreementand Plan of Merger, dated as of October 15, 2000. As a result of theMerger, Texaco Inc. became a wholly owned subsidiary of Chevron Corporation,and Chevron Corporation changed its name to “ChevronTexaco Corporation” inconnection with the Merger (ChevronTexaco Corporation is referred to herein as “ChevronTexaco”).Accordingly, the properties referred to herein by Chevron and Texaco are eachnow controlled by a subsidiaries of ChevronTexaco.

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 East Cameron 354field subject to a 25% Net Profit Interest property from Amerada effective April 1,2003. As a result of this transaction, Anadarko replaced Amerada as the WorkingInterest Owner of East Cameron 354 effective July 1, 2003 and also assumedAmerada’s obligations under the Conveyance 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 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 I through October 31, 1986; Tenneco for periods from October 31,1986 until November 18, 1988; Chevron with respect to all RoyaltyProperties for periods from November 18, 1988 until October 30, 1992,and with respect to all Royalty Properties except East Cameron 354, EugeneIsland 348, Eugene Island 367 and Eugene Island 208 for periods from October 30,1992 until December 1, 1994, and with respect to the same propertiesexcept West Cameron 643 thereafter; PennzEnergy/Devon with respect to EastCameron 354, Eugene Island 348, Eugene Island 367 and Eugene/Devon Island208 for periods from October 30, 1992 until October 1, 1995, and withrespect to Eugene Island 348 and Eugene Island 208 thereafter; TEPI withrespect to West Cameron 643 and East Cameron 371/381 for periods beginning onor after December 1, 1994 until May 1, 2002; 

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SONATwith respect to East Cameron 354 for periods beginning on or after October 1,1995; Amoco with respect to Eugene Island 367 for periods beginning on or afterOctober 1, 1995; Amerada with respect to East Cameron 354 for periodsbeginning on or after January 1, 1998; Chevron with respect to West Cameron643 and East Cameron 371/381 on and after May 1, 2002; Anadarko withrespect to East Cameron 354 on and after July 1, 2003 untilOctober 1, 2004; and Apache with respect to East Cameron 354 afterOctober 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 theCorporate Trust, Texas Commerce Bank National Association) (“Corporate Trustee”)in accordance with the instructions to Form 10-Q and does notinclude all of the information required by accounting principles generallyaccepted in the United States of America for complete financial statements,although the Corporate 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 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 Note 6); 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 Interest Owners.The financial statements of the Trust differ from financial statements preparedin accordance with generally accepted accounting principles, because, undersuch principles, Royalty income and Trust general and administrative expensesfor a quarter would be recognized on an accrual basis. In addition,amortization of the net overriding royalty interest, which is calculated on aunits-of-production basis, is charged directly to Trust corpus since suchamount does not affect distributable income.

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

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

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

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

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

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

**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, applicabletaxes other than income taxes, and the Special Cost Escrow account. The SpecialCost Escrow account (See Note 6) is established for the future costs to beincurred to plug and abandon wells, dismantle and remove platforms, pipelinesand other production facilities, and for the estimated amount of future capitalexpenditures on the Royalty Properties. Net Proceeds do not include amountsreceived by the Working Interest Owners as advance gas payments, “take-or-pay”payments or similar payments unless and until such payments are extinguished orrepaid through the future delivery of gas.

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**Note 4—Distributions to Unit Holders**

In accordance with the provisions of the TrustAgreement, generally all Net Proceeds received by the Trust, net of Trustgeneral and administrative expenses and any cash reserves established for thepayment of contingent or future obligations of the Trust, are distributedcurrently to the Unit holders. Such distributions are referred to as “distributableincome.” The amounts distributed are determined on a quarterly basis and arepayable to Unit holders of record as of the last business day of each calendarquarter. 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). As a result of these negativeadjustments, the Trust at March 31, 2004 had a loss carryforward of$3,307,628. In the second quarter of 2004, Net Proceeds were offset by the losscarryforward of $3,307,628 with a resulting loss carryforward balance of $0 at June 30,2004. No distributable income was available to Unit holders in the secondquarter since the Trust recoups expenses being paid from the reserve for Trustexpense that the Trustees have established for anticipated future expenses. Duringthe quarter ended September 30, 2004, the Trust resumed distributions asthe reserve for 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 of the Partnership, has advised the Trust that theseerrors 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 sufficient to fully offset the loss carryforward of$3,307,628, resulting 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 nine months of 2004, there wasa net release of funds from the Special Cost Escrow account. The Trust’s shareof the funds released was $2,128,752. The release was primarily due to adecrease of $6,770,467 in projected special costs for capital expenditures. Inthe first nine months of 2005, the Trust’s share of the net release of funds fromthe Special Cost Escrow Account was $61,287. In the three months endedSeptember 30, 2004, there was a net release of funds from the Special CostEscrow account of $947,568 compared to a net release of $2,337,030 for thethree months ended September 30, 2005. As of September 30, 2005,$5,415,251 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 September 30,2005 was $1,442,509. The reserve amount at December 31, 2004 was$1,341,014.

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

**CriticalAccounting 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.

(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**

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

Distributions to the Unitholders for the three months ended September 30, 2005 amounted to$5,447,639 or $1.146507 per Unit as compared to $2,874,011 or $.604863 per Unitfor the same period in 2004. The increase in distributable income for the thirdquarter of 2005 was primarily due to increases in both oil and gas prices, aswell as a release of approximately $2,337,030 from the Special Cost Escrow account,as described below.

Crude oil and condensaterevenues increased 13% to $9,485,345 in the third quarter of 2005 from$8,391,210 in the third quarter of 2004 due to a 41% increase in the averageprice of crude oil and condensate from $36.04 per barrel in the third quarterof 2004 to $50.94 in the same period in 2005. The increase was partially offsetby a 20% decrease in crude oil and condensate volume to 186,210 barrels in thethird quarter of 2005 from, 232,854 barrels in the third quarter of 2004.

Natural gas and gas productsrevenues decreased 3.5% to $5,500,203 in the third quarter of 2005 from$5,700,826 in the third quarter of 2004, primarily due to a 17% decrease in naturalgas volumes to 708,345 Mcf in the third quarter of 2005 from 856,414 Mcf in thethird quarter of 2004. Gas products volumes also decreased by 133,468 gallons,or 24%, to 422,508 gallons in 2005 from 555,976 gallons in the third quarter of2004. These decreases were partially offset by a 16% increase in the averageprice received for natural gas to $7.29 per Mcf in the third quarter of 2005from $6.29 per Mcf in the third quarter of 2004.

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Capital expendituresdecreased 84% to $515,985 in the third quarter of 2005, as compared to$3,263,473 in the third quarter of 2004. The higher capital expenditures in thethird quarter of 2004 were due primarily to charges for the B-2 side-track onEugene Island 339.

In the third quarter of2005, there was a net release of funds from the Special Cost Escrow account.The Trust’s share of the funds released was $2,337,030 as compared to $947,568released in the third quarter of 2004. 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.

**NineMonths Ended September 30, 2005 and 2004**

Distribution to the UnitHolders for the nine months ended September 30, 2005 amounted to$7,428,599 or $.563419 per Unit as compared to $2,874,011 or $.604863 per Unitfor the same period in 2004. The increase in distributable income during thenine-month period in 2005 was due primarily to increases in both oil and gasprices, as well as the negative adjustments recorded in 2004.

Crude oil and condensaterevenues increased $10,588,929, or 69%, to $25,837,849 in the first nine monthsof 2005 as compared to $15,248,920 for the same period in 2004, due to a 36%increase in crude oil and condensate volume to 546,766 barrels in the firstnine months of 2005 from 403,237 barrels for the same period in 2004. Therevenues and volumes for the first nine months of 2004 include negativeadjustments, as a result of the improper credits of production and revenues by Chevron,totaling 295,224 barrels recorded by the Trust in the first quarter of 2004.The average price of crude oil and condensate increased from $37.82 per barrelin the first nine months of 2004 to $47.26 per barrel for the same period in2005.

Natural gas and gasproducts revenues increased 4% to $13,198,159 in the first nine months of 2005from $12,714,776 for the same period in 2004, primarily due to a 16% increasein the average price received for natural gas to $7.05 per Mcf in the firstnine months of 2005 from $6.07 per Mcf in the same period of 2004. The priceincrease is offset by an 11% decrease in natural gas volumes to 1,706,002 Mcfin the first nine months of 2005 from 1,924,360 Mcf for the same period in2004. Gas products volumes also decreased by 458,615 gallons, or 24% to1,461,004 gallons in the first nine months of 2005 compared to 1,919,619gallons in the same period for 2004. The production for the first nine monthsof 2004 includes negative adjustments resulting from the improper credits ofproduction and revenues by Chevron.

Capital expendituresdecreased $15,279,861, from $17,790,751 in the first nine months of 2004 to$2,510,890 in the same period of 2005. Thedecrease in capital expenditures for the first nine months of 2005 relatedprimarily to the drilling of the new I-4 well and some residual costsfrom the completion of the I-2 and I-3 wells on the Ship Shoal182/183 property in the first quarter of 2004, compared to capital expendituresfor the same period in 2005 which were related to the purchase of a compressoron the Ship Shoal 182/183 property and some residual costs from wellcompletions on Eugene Island 339. The Trust recorded an adjustment of$2,026,684 in the first quarter of 2004 relating primarily to charges incurredin the fourth quarter of 2003. Adjustments to capital expenditures are based onmiscalculations and duplication of downward adjustments allocations on ShipShoal 182/183 during the third and fourth quarters of 2003. Thesemiscalculations and duplications are reflected in the amounts provided.

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TheTrust did not have undistributed net income in the first nine months of 2005.As discussed above, Net Proceeds during the second quarter of 2004 were offsetby the loss carryforward of $3,307,863 existing as of March 31, 2004,resulting in a loss carryforward balance of $0 at June 30, 2004.

In the first nine monthsof 2005, there was a net release of funds from the Special Cost Escrow account.The Trust’s share of the funds released was $61,287 compared to a net releaseof funds of $2,128,752 in the first nine months of 2004. As of September 30,2005, $5,415,251 remained in the Special Cost Escrowaccount. The Special Cost Escrow is set aside for estimatedabandonment costs and future capital expenditures, as provided for in theConveyance. For additional information relating to the Special Cost Escrow,see “—Special Cost Escrow Account” below.

**Reservefor 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 December 31,2004 was $1,341,014. The reserve amount for September 30, 2005 was$1,442,509.

**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**

**ThreeMonths Ended September 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 increased from $4,879,287 in the third quarter of 2004 to$5,285,070 in the third quarter of 2005, primarily due to an increase in theaverage crude oil price from $36.73 per barrel in the third quarter of 2004 to$52.31 per barrel for the same period in 2005. The increase was partiallyoffset by a decrease in crude oil production from 132,838 barrels in the thirdquarter of 2004 to 101,042 barrels in the third quarter of 2005. Gas revenuesdecreased from $3,837,637 in the third quarter of 2004 to $2,006,142 in thethird quarter of 2005, primarily due to a decrease in gas production. Gasvolumes decreased from 608,639 Mcf in the third quarter of 2004 to 272,592 Mcfin the third quarter of 2005. The decrease was partially offset by an increasein natural gas sales price from $6.31 per Mcf in the 

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thirdquarter of 2004 to $7.36 per Mcf in the third quarter of 2005. The decrease ingas volumes was primarily due to the field being shut-in for 13 days forpipeline repairs. Capital expenditures increased from $190,336 in the thirdquarter of 2004 to $316,857 in the third quarter of 2005. The increase incapital expenditures was primarily due to a new compressor installation onPlatform C. Operating expenses increased slightly from $403,157 in the thirdquarter of 2004 to $408,785 for the same period in 2005.

Eugene Island 339 crudeoil revenues increased from $3,388,028 in the third quarter of 2004 to$4,088,063 in the third quarter of 2005, partially offset by a decrease incrude oil production from 96,577 barrels in the third quarter of 2004 to 82,927barrels in the third quarter of 2005, primarily due to repair work in June 2005.The average price of crude oil increased from $35.08 per barrel in the thirdquarter of 2004 to $49.30 in the third quarter of 2005. Gas revenues increasedfrom $1,086,662 in the third quarter of 2004 to $1,575,929 in the third quarterof 2005, primarily due to a production increase from 172,307 Mcf in the thirdquarter of 2004 to 212,419 in the third quarter of 2005. The average naturalgas sales price increased from $6.31 per Mcf in the third quarter of 2004 to$7.42 per Mcf in the third quarter of 2005. Capital expenditures decreased from$3,021,559 in the third quarter of 2004 to $162,771 in the third quarter of2005. Operating expenses increased slightly from $314,959 in the third quarterof 2004 to $399,954 for the same period in 2005.

West Cameron 643 gasrevenues increased from $326,340 in the third quarter of 2004 to $1,549,572 inthe third quarter of 2005. The increase in gas revenues was primarily due to asuccessful workover on the A-14 well. Gas volumes increased from 53,240Mcf in the third quarter of 2004 to 218,322 Mcf in the third quarter of2005.The average price received for natural gas increased from $6.13 per Mcf inthe third quarter of 2004 to $7.10 for the same period in 2005. Operatingexpenses increased from $64,731 in the third quarter of 2004 to $140,268 forthe same period in 2005. Capital expenditures increased from $5,312 in thethird quarter of 2004 to $30,821 in the third quarter of 2005.

East Cameron 371/381 crudeoil revenues decreased from $10,884 in the third quarter of 2004 to $197 in thethird quarter of 2005, partially offset by an increase in the average pricereceived of $40.92 per barrel in the third quarter of 2004 to $52.87 per barrelin the third quarter of 2005. The price increase was partially offset by adecrease in crude oil production from 266 barrels in the third quarter of 2004to 4 barrels in the same period in 2005. Gas revenues decreased from $29,453 inthe third quarter of 2004 to $8,681 in the third quarter of 2005. This decreasewas primarily due to a decrease in gas volumes from 5,032 Mcf in the thirdquarter of 2004 to 1,280 Mcf in the third quarter of 2005. This volume decreasewas partially offset by an increase in the average natural gas sales price from$5.85 per Mcf in the third quarter of 2004 to $6.78 per Mcf in the thirdquarter of 2005. Operating expenses decreased from $6,242 in the third quarterof 2004 to $4,167 in the third quarter of 2005. There were no capital expensesin the third quarter of 2005 as compared to $173 for the same period in 2004.

At the end of October2005, approximately half of Chevron oil-equivalent production in the Gulf ofMexico remained shut in due to damages from hurricanes in the thirdquarter.  The time it will take to resumethis production is uncertain, and some of the volumes may not be sufficientlyeconomic to restore. The impact to the Trust properties is estimated to be a68% reduction in Oil Equivalent Gas production. Eugene Island 339 remainsshut-in for a loss of approximately 1,360 Oil Equivalent Gas per day, and ShipShoal 182/183 gas production is shut-in due to Tennessee Gas pipeline beingdown for a loss of approximately 950 Oil Equivalent Gas. 

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**Nine Months EndedSeptember 30, 2005 and 2004**

*Volumes and dollaramounts discussed below represent amounts recorded by the Working InterestOwners unless otherwise specified.*

During the firstquarter of 2004, a Working Interest Owner informed the Trust that it had madeerrors in prior periods which resulted in prior periods Net Proceeds beingoverstated. This Working Interest Owner, Chevron, which is also the ManagingGeneral Partner of the Partnership, has advised the Trust that these errorsconsisted of:

·  Eugene Island 339—a $6,953,982 gross revenueadjustment to reverse revenues previously credited to the Trust for an interestin wells that the Trust does not hold an interest, a $98,797 gross operatingexpense adjustment and a $573,382 adjustment to increase previous capitalexpenditures

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

·  South Timbalier 36/37 (Royalty Propertiesassociated with ChevronTexaco)—a $495,425 gross adjustment to reverse theeffects of clerical errors.

The gross adjustments, before the Special Cost Escrowaccount adjustment, were $10,911,175 or a $2,727,521 increase to $3,307,628 inthe losses to be carried forward and netted against future Net Proceeds earnedby the Trust on Royalty Properties operated by this Working Interest Owner asof March 31, 2004. In the second quarter of 2004, Net Proceeds weresufficient to fully offset the loss carryforward of $3,307,628, resulting in nofurther loss carryforward.

Ship Shoal 182/183 crude oil revenues increased from$11,586,941 in the first nine months of 2004 to $13,383,678 in the first ninemonths of 2005, partially offset by a decline in crude oil production from336,072 barrels in the first nine months of 2004 to 272,333 barrels in thefirst nine months of 2005. The decrease was partially offset by an increase inthe average crude oil price from $34.48 per barrel in the first nine months of2004 to $49.14 per barrel for the same period in 2005. Gas revenues decreasedfrom $8,254,336 in the first nine months of 2004 to $5,068,228 in first ninemonths of 2005 primarily due to a significant decrease in gas volumes from1,369,788 Mcf in the first nine months of 2004 to 715,058 Mcf for the sameperiod in 2005. The average natural gas sales price increased from $6.03 perMcf in the first nine months of 2004 to $7.09 in the first nine months of 2005.Capital expenditures decreased from $8,040,549 in the first nine months of 2004to $1,477,630 in the same period of 2005, primarily due to $6.3 million ofcapital expenditures made to complete the F-3 drilling project in 2004.Operating expenses decreased from $2,110,160 for the first nine months of 2004to $1,079,065 for the first nine months of 2005.

Eugene Island 339 crude oil revenues increased from$3,728,107 in the first nine months of 2004 to $12,140,854 in the first ninemonths of 2005, primarily due to an increase in volumes from 70,198 barrels inthe first nine months of 2004 to 268,139 barrels in the first nine months of2005. The price of crude oil increased from $31.53 per barrel in the first ninemonths of 2004 to $45.28 per barrel in the first nine months of 2005. Gasrevenues increased from $2,270,350 in the first nine months of 2004 to$4,753,004 in the first nine months of 2005, primarily due to an increase inproduction from 354,018 Mcf for the first nine months of 2004 to 665,035 Mcffor the same period in 2005. Capital expenditures decreased from 

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$9,673,067 in the firstnine months of 2004 to $905,891 in the first nine months of 2005, due tovarious capital projects that were completed in the first six months of 2004,including: (i) the C-20 and C-21 drilling projects that costapproximately $1.5 million and $3.3 million, respectively; (ii) upgrades to theC platform facilities that cost approximately $517,000; and (iii) the third-quarter2004 B-2 sidetrack project costing $3.2 million. Operating expensesdecreased from $1,260,322 for the first nine months of 2004 to $1,059,559 forthe first nine months of 2005.

West Cameron 643 gas revenues increased from $804,828in the first nine months of 2004 to $2,197,951 in the first nine months of2005, primarily due to an increase in gas volumes from 144,043 Mcf in the firstnine months of 2004 to 328,735 Mcf for the same period in 2005. Operatingexpenses increased from $218,875 in the first nine months of 2004 to $1,192,832for the first nine months of 2005, primarily due to a workover expense of$750,000 incurred in 2005. Capital expenditures increased from $7,893 in thefirst nine months of 2004 to $83,913 in the first nine months of 2005.

East Cameron 371/381 crudeoil revenues decreased from $28,938 in the first nine months of 2004 to($42,369) in the first nine months of 2005 due in part to a decrease in crudeoil production from 794 barrels in the first nine months of 2004 to (1,223)barrels in the first nine months of 2005. Gas revenues decreased from $78,930in the first nine months of 2004 to ($81,934) in the first nine months of 2005.Operating expenses decreased from $23,313 in the first nine months of 2004 to ($15,451)in the first nine months of 2005. Capital expenditures decreased from $1,496 inthe first nine months of 2004 to ($1,560) in the first nine months of 2005. Thedecreases for East Cameron 371/381 are due in part to the Working InterestOwner including production and expenses in previous quarters related to theEast Cameron 381 block wells A-1 and A-3 in the Trust’s activity and the Trustnot having 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 approximated $30.2million. Estimates of proved oil and gas reserves attributable to thePartnership’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 terminate eventhough 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, annual production andcosts assumed by DeGolyer and MacNaughton. In addition, future economic andoperating conditions as well as results of future drilling plans may causesignificant changes in such estimate. The discussion set forth above isqualified in its entirety by reference to the 

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Trust’s2004 Annual Report on Form 10-K. The Form 10-K isavailable upon request from the Corporate Trustee.

**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 proceeds. 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 proceeds to pay suchcosts. Special Costs that have been paid are no longer included in the SpecialCost Escrow calculation. Deposits to the Special Cost Escrow Account willgenerally be made when the balance in the Special Cost Escrow Account is lessthan 125% of future Special Costs and there is a Net Revenues Shortfall (acalculation of the excess of estimated future costs over estimated future netrevenues pursuant to a formula contained in the Conveyance). When there is nota Net Revenues Shortfall, amounts in the Special Cost Escrow Account willgenerally be released, to the extent that Special Costs have been incurred.Amounts in the Special Cost Escrow Account generally will also be released whenthe balance in such account exceeds 125% of future Special Costs. In the firstnine months of 2005, the Trust’s share of the net release of funds from theSpecial Cost Escrow Account was $61,287. In the first nine months of 2004,there was a net release of funds from the Special Escrow Account. The Trust’sshare of the funds released was $2,128,752. The release was primarily to aresult of a decrease of $6,770,487 in projected special costs for capitalexpenditures. In the three months ended September 30, 2004, there was anet release of funds from the Special Cost Escrow account of $947,568 comparedto a net release of $2,337,030 for the three months ended September 30,2005. As of September 30, 2005, $5,415,251 remained in the Special CostEscrow Account.

Chevron, in its capacityas Managing General Partner of the Partnership, has advised the Trust that additionaldeposits to the Special Cost Escrow Account may be required in future periodsin connection with other production costs, other abandonment costs, othercapital expenditures and changes in the estimates and factors described above.Such deposits, if made, could result in a significant reduction in Royaltyincome in the periods in which such deposits are made, including thepossibility that no Royalty income would be received in such periods.

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**Overviewof Production, Prices and Net Proceeds**

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

| ** **                                                   | ** ** | **Royalty Properties  Three Months Ended  September 30,(1)** | ** ** |
|--------------------------------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2005**                                                                         | ** ** | **2004** | ** ** |
| Crude oil and  condensate (bbls)                             |       | 186,210                                                                          |       | 232,854 |   |
| Natural gas and  gas products (Mcfe)                         |       | 768,703                                                                          |       | 935,839 |   |
| Crude oil and  condensate average price, per bbl             |       | $                                                                                | 50.94      |   | $ | 36.04 |   |
| Natural gas  average price, per Mcf (excluding gas products) |       | $                                                                                | 7.29       |   | $ | 6.29 |   |
| Crude oil and  condensate revenues                           |       | $                                                                                | 9,485,345  |   | $ | 8,391,210 |   |
| Natural gas and  gas products revenues                       |       | 5,500,203                                                                        |       | 5,700,826 |   |
| Production  expenses                                         |       | (1,469,787                                                                       | )          | (1,353,519 | ) |
| Capital  expenditures                                        |       | (515,985                                                                         | )          | (3,263,473 | ) |
| Undistributed Net  Income(2)                                 |       | 0                                                                                |       | 0 |   |
| Refund  Of/(Provision for) Special Cost Escrow               |       | 9,369,747                                                                        |       | 3,790,660 |   |
| **Net  Proceeds**                                            |       | 22,369,524                                                                       |       | 13,265,704 |   |
| Royalty interest                                             |       | x25                                                                              | %          | x25 | % |
| Partnership share                                            |       | 5,592,381                                                                        |       | 3,316,426 |   |
| Trust interest                                               |       | x99.99                                                                           | %          | x99.99 | % |
| Trust share of Royalty  Income                               |       | $                                                                                | 5,591,822  |   | $ | 3,316,095 |   |

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(1)          The amounts for thethree months ended September 30, 2005 and 2004 represent actual productionfor the periods May 2005 through July 2005, and May 2004 throughJuly 2004, respectively.

(2)          Undistributednet loss represents negative Net Proceeds generated during the respectiveperiod. An undistributed net loss is carried forward and offset, in futureperiods, by positive Net Proceeds, earned by the related Working InterestOwner(s). Undistributed net income represents positive Net Proceeds, generatedduring the respective period, that were applied to an existing losscarryforward. As of September 30, 2005, the loss carryforward was $0.

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| ** **                                                      | ** ** | **Royalty Properties  Nine Months Ended  September 30,(1)** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2005**                                                                        | ** ** | **2004** | ** ** |
| Crude oil and  condensate (bbls)(2)                             |       | 546,766                                                                         |       | 403,237 |   |
| Natural gas and  gas products (Mcfe)(3)                         |       | 1,914,717                                                                       |       | 2,198,591 |   |
| Crude oil and  condensate average price, per bbl(2)             |       | $                                                                               | 47.26      |   | $ | 31.01 |   |
| Natural gas average  price, per Mcf (excluding gas products)(3) |       | $                                                                               | 7.05       |   | $ | 6.07 |   |
| Crude oil and  condensate revenues(2)                           |       | $                                                                               | 25,837,849 |   | $ | 15,248,920 |   |
| Natural gas and  gas products revenues(3)                       |       | 13,198,159                                                                      |       | 12,714,775 |   |
| Production  expenses(4)                                         |       | (4,710,966                                                                      | )          | (5,145,996 | ) |
| Capital  expenditures(4)                                        |       | (2,510,890                                                                      | )          | (17,790,751 | ) |
| Undistributed Net  Loss (Income)(5)                             |       | 0                                                                               |       | (1,356,586 | ) |
| Refund of/  (Provision for) Special Cost Escrow                 |       | 245,148                                                                         |       | 9,930,800 |   |
| **Net  Proceeds**                                               |       | 32,059,300                                                                      |       | 13,601,163 |   |
| Royalty interest                                                |       | x25                                                                             | %          | x25 | % |
| Partnership share                                               |       | 8,014,825                                                                       |       | 3,400,291 |   |
| Trust interest                                                  |       | x99.99                                                                          | %          | x99.99 | % |
| Trust share of Royalty  Income                                  |       | $                                                                               | 8,014,024  |   | $ | 3,399,952 |   |

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(1)          The amounts for the ninemonths ended September 30, 2005 and 2004 represent actual production for theperiods November 2004 through July 2005, and November 2003through July 2004, respectively.

(2)          Includes negative volumeadjustments of 295,224 bbls for the nine months ended September 30, 2004.Exclusive of these adjustments, volumes would have been 698,461 bbls. Excludingthe impact of these adjustments crude oil and condensate average price per bblwould have been $33.62. Excluding the impact of these adjustments crude oil andcondensate revenues would have been $23,481,291.

(3)          Includes negative volumeadjustments of 203,181 Mcf for the nine months ended September 30, 2004.Exclusive of these adjustments volumes would have been 3,547,159 Mcf. Excludingthe impact of these adjustments natural gas average price per Mcf would havebeen $5.48 and natural gas and natural gas liquids revenue would have been$19,449,927.

(4)          Includes negativeadjustments of $2,153,785 for the nine months ended September 30, 2004.Excluding the impact of these adjustments, production expense would have been$5,047,199 and capital expenditures would have been $19,845,739.

(5)          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 September 30, 2004, Net Proceeds were offset by theloss carryforward of $3,307,628 existing as of March 31, 2004. At September 30,2004, there was no additional loss carryforward.

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**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.

**Item 4.**                        Controlsand Procedures.

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

The Corporate Trustee maintains disclosure controlsand procedures designed to ensure that information to be disclosed by the Trustin the reports that it files or submits under the Exchange Act of 1934, asamended, is recorded, processed, summarized and reported within the timeperiods specified in the SEC’s rules and regulations. Disclosure controlsand procedures include controls and procedures designed to ensure thatinformation required to be disclosed by the Trust is accumulated andcommunicated by Chevron as the managing general partner of the Partnership, andthe working interest owners to JPMorgan Chase Bank, N.A., as Corporate Trusteeof the Trust, and its employees who participate in the preparation of the Trust’speriodic reports as appropriate to allow timely decisions regarding requireddisclosure.

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 controld 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 bythe Working Interest Owners, including historical operating data, plans forfuture operating and capital expenditures, reserve information and information relatingto projected production, (B) information from the managing generalparternof the Partnership, including information that is collected from theWorking Interest Owners, and (C) conclusions and reports regardingreserves by the Trust’s independent reserve engineers. See Item 1 “Business—PrincipleTrust Risk Factors—None of the Trustees, the Trust nor its Unit holders controlthe operation or development of the Royalty Properties and have littleinfluence over operation or development” in the Trust’s Form 10-K,and “Note 5—Negative Adjustments” of the financial statements and “Management’sDiscussion and Analysis of Financial Condition and Results of Operating”relating to operating information on East Cameron 371/381 included in this form10-Q, for a decription of certain risks relating to these arrangementsand reliance and applicable adjustments to operating information when reportedby the Working Interest Owners to the Corporate Trustee and recorded in theTrust’s results of operation.

*Changesin Internal Control Over Financial Reporting.**  *During the three months ended September 30,2005, there has been no change in the Corporate Trustee’s internal control overfinancial reporting that has materially affected, or is reasonably likely tomaterially affect, the Corporate Trustee’s internal control over financialreporting relating to the Trust. The Corporate Trustee notes for purposes ofclarification that it has no authority over, and makes no statement concerning,the internal control over financial reporting of the Working Interest Owners orthe managing general partner of the Partnership.

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**PART II—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,  Corporate Trustee |
|                          | By:                 | /s/  MIKE ULRICH |
|                          | ** **          | **Mike  Ulrich** |
|                          | ** **          | ***Vice  President*** |
| Date:  November 14, 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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