**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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**FORM 10-Q**
| **x**  | **Quarterly Report Pursuant to Section 13 or  15(d) of the Securities Exchange Act of 1934 for the quarterly period  ended September 30, 2004**                                                                                                                                                                                                                                                                    |
|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **or** |
| **o**  | **Transition Report Pursuant to  Section 13 or 15(d) of the Securities Exchange Act of 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, Trustee  Institutional Trust Services  700 Lavaca Street  Austin, Texas** | **78701**                             |
| (Address of  Principal  Executive Offices)                                                       | (Zip Code)                            |
| Registrant’s  Telephone Number, 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 the number ofshares outstanding of each of the registrant’s classes of common stock, as ofthe latest practicable date.

Asof November 12, 2004—4,751,510Units of Beneficial Interest in TEL Offshore Trust.

 

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**PART I—FINANCIAL INFORMATION**

**Item 1. Financial Statements.**

**STATEMENTSOF ASSETS, LIABILITIES AND TRUST CORPUS(Unaudited)**
| ** **                                                                                                                                | ** ** | **  September 30,    2004** | ** ** | **  December 31,    2003** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| **Assets**                                                                                                                                |       |                                                 |       |                                                |       |   |   |   |   |
| Cash and cash  equivalents                                                                                                                |       |                                                 | $          | 4,207,845                                           |       |   |   | $ | 1,952,547 |   |   |
| Net overriding  royalty interest in oil and gas properties, net of accumulated amortization  of $28,156,194 and $28,113,036, respectively |       |                                                 | 111,461    |                                                |       |   | 154,619 |   |   |
| Total assets                                                                                                                              |       |                                                 | $          | 4,319,306                                           |       |   |   | $ | 2,107,166 |   |   |
| **Liabilities  and Trust Corpus**                                                                                                         |       |                                                 |       |                                                |       |   |   |   |   |
| Distribution  payable to Unit holders                                                                                                     |       |                                                 | $          | 2,874,011                                           |       |   |   | $ | 588,136 |   |   |
| Reserve for  future Trust expenses                                                                                                        |       |                                                 | 1,333,834  |                                                |       |   | 1,364,411 |   |   |
| Commitments and  contingencies                                                                                                            |       |                                                 |       |                                                |       |   |   |   |   |
| Trust corpus  (4,751,510 Units of beneficial interest authorized and outstanding)                                                         |       |                                                 | 111,461    |                                                |       |   | 154,619 |   |   |
| Total liabilities and  Trust corpus                                                                                                       |       |                                                 | $          | 4,319,306                                           |       |   |   | $ | 2,107,166 |   |   |
|                                                                                                                                      |       |                                                 |       |                                                |       |   |   |   |   |

 

**STATEMENTS OF DISTRIBUTABLE INCOME(Unaudited)**
| ** **                                                | ** ** | **Three Months Ended  September 30,**     | ** ** | **Nine Months Ended  September 30,**      | ** ** |
|-----------------------------------------------------------|------------|----------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                | ** ** | **    2004    ** | ** ** | **    2003    ** | ** ** | **    2004    ** | ** ** | **    2003    ** | ** ** |
| Royalty income                                            |       | $                                                        | 3,316,095  |                                                     | $          | 1,443,095 |   | $ | 3,399,952 |   | $ | 3,480,192 |   |
| Interest income                                           |       | 1,819                                                    |       | 1,767                                                    |       | 5,039 |   | 5,830 |   |
|                                                      |       | 3,317,914                                                |       | 1,444,862                                                |       | 3,404,991 |   | 3,486,022 |   |
| (Increase)/Decrease  in reserve for future Trust expenses |       | (347,290                                                 | )          | 0                                                        |       | (148,151 | ) | 28,194 |   |
| General and  administrative expenses                      |       | (96,613                                                  | )          | (145,797                                                 | )          | (382,829 | ) | (542,964 | ) |
| Other—Texaco  Settlement Agreement (Note 8)          |       | 0                                                        |       | 75,000                                                   |       | 0 |   | 75,000 |   |
| Distributable  income                                     |       | $                                                        | 2,874,011  |                                                     | $          | 1,374,065 |   | $ | 2,874,011 |   | $ | 3,046,252 |   |
| Distributions per Unit  (4,751,510 Units)                 |       | $                                                        | .604863    |                                                     | $          | .289185 |   | $ | .604863 |   | $ | .641112 |   |

 

The accompanying notes arean integral part of these financial statements.

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**STATEMENTS OF CHANGES IN TRUST CORPUS(Unaudited)**
| ** **                                       | ** ** | **Three Months Ended  September 30,**     | ** ** | **Nine Months Ended  September 30,**      | ** ** |
|--------------------------------------------------|------------|----------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                       | ** ** | **    2004    ** | ** ** | **    2003    ** | ** ** | **    2004    ** | ** ** | **    2003    ** | ** ** |
| Trust corpus,  beginning of period               |       | $                                                        | 124,601    |                                                     | $          | 178,985 |   | $ | 154,619 |   | $ | 192,440 |   |
| Distributable  income                            |       | 2,874,011                                                |       | 1,374,065                                                |       | 2,874,011 |   | 3,046,252 |   |
| Distribution  payable to Unit holders            |       | (2,874,011                                               | )          | (1,374,065                                               | )          | (2,874,011 | ) | (3,046,252 | ) |
| Amortization of  net overriding royalty interest |       | (13,140                                                  | )          | (17,802                                                  | )          | (43,158 | ) | (31,257 | ) |
| Trust corpus, end of  period                     |       | $                                                        | 111,461    |                                                     | $          | 161,183 |   | $ | 111,461 |   | $ | 161,183 |   |
|                                             |       |                                                     |       |                                                     |       |   |   |   |   |

 

The accompanying notes are an integral part of these financialstatements.

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS (Unaudited)**

**Note 1 — TrustOrganization**

Tenneco Offshore Company, Inc.(“Tenneco Offshore”) created the TEL Offshore Trust (“Trust”) effective January 1,1983, pursuant to the Plan of Dissolution (“Plan”) approved by Tenneco Offshore’sstockholders on December 22, 1982. In accordance with the Plan, the TELOffshore Trust Partnership (“Partnership”) was formed in which the Trust owns a99.99% interest and Tenneco Oil Company (“Tenneco”) initially owned a .01%interest. In general, the Plan was effected by transferring an overridingroyalty interest (“Royalty”) equivalent to a 25% net profits interest in theoil and gas properties (the “Royalty Properties”) of 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 dissolved and the oil and gas properties of Exploration Iwere distributed to Tenneco subject to the Royalty. Tenneco, who was thenserving as the Managing General Partner of the Partnership, assumed theobligations of Exploration I, including its obligations under the instrumentconveying the Royalty to the Partnership (the “Conveyance”). The dissolution ofExploration I had no impact on future cash distributions to holders of units ofbeneficial interest.

On November 18, 1988,Chevron U.S.A., Inc. (“Chevron”) acquired most of the Gulf of Mexicooffshore oil and gas properties of Tenneco, including all of the RoyaltyProperties. As a result of the acquisition, Chevron replaced Tenneco as theWorking Interest Owner and Managing General Partner of the Partnership. Chevronalso assumed Tenneco’s obligations under the Conveyance.

On October 30, 1992,PennzEnergy Company (“PennzEnergy”) (which merged with and into Devon EnergyProduction Company L.P. effective January 1, 2000) acquired certain oiland gas producing properties from Chevron, including four of the RoyaltyProperties. The four Royalty Properties acquired by PennzEnergy were EastCameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As aresult of such acquisition, PennzEnergy replaced Chevron as the WorkingInterest Owner of such properties on October 30, 1992. PennzEnergy alsoassumed Chevron’s obligations under the Conveyance with respect to theseproperties.

On December 1, 1994,Texaco Exploration and Production Inc. (“TEPI”) acquired two of the RoyaltyProperties from Chevron. The Royalty Properties acquired by Texaco were WestCameron 643 and East Cameron 371/381. As a result of such acquisitions, TEPIreplaced Chevron 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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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued) (Unaudited)**

**Note 1 —Trust Organization (Continued)**

Island367 properties, respectively, on October 1, 1995 and also assumedPennzEnergy’s obligations under the Conveyance with respect to these properties.

Effective January 1,1998, Energy Resource Technology, Inc. (“ERT”) acquired the East Cameron354 property from SONAT. As a result of such acquisition, ERT replaced SONAT asthe Working Interest Owner of the East Cameron 354 property effective January 1,1998, and also assumed SONAT’s obligations under the Conveyance with respect tosuch property. In October 1998, Amerada Hess Corporation (“Amerada”)acquired the East Cameron 354 property from ERT effective January 1, 1998.As a result of such acquisition, Amerada replaced ERT as the Working InterestOwner of 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 Devon Energy Corporation (Nevada) merged into Devon EnergyProduction Company L.P. (“Devon”). As a result of such merger, Devon replacedPennzEnergy as the Working Interest Owner of Eugene Island 348 and EugeneIsland 208 properties effective January 1, 2000, and also assumedPennzEnergy’s obligations under the Conveyance with respect to theseproperties.

On October 9, 2001, awholly owned subsidiary of Chevron Corporation, a Delaware corporation, merged(the “Merger”) with and into Texaco Inc., a Delaware corporation (“Texaco”),pursuant to an Agreement and Plan of Merger, dated as of October 15, 2000.As a result of the Merger, Texaco Inc. became a wholly owned subsidiary ofChevron Corporation, 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 a subsidiaries ofChevronTexaco.

On May 1, 2002, TEPIassigned all of its interests in West Cameron 643 and East Cameron 371/381 toChevron. Accordingly, pursuant to the Conveyance of the Royalty Properties, netprofits interest will be calculated for the collective Royalty Properties ownedby Chevron after this date.

On June 6, 2003Anadarko Petroleum Corporation (“Anadarko”) acquired, among other interests, a25% Working Interest in the East Cameron 354 field subject to a 25% Net ProfitInterest property from Amerada effective April 1, 2003. As a result ofthis transaction, Anadarko replaced Amerada as the Working Interest Owner ofEast Cameron 354 effective July 1, 2003 and also assumed Amerada’sobligations under the Conveyance with respect to said property.

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

Unless the context in which such terms are usedindicates otherwise, in these Notes to Financial Statements the terms “WorkingInterest Owner” and “Working Interest Owners” generally refer to the

4

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued) (Unaudited)**

**Note 1 —Trust Organization (Continued)**

owner orowners of the Royalty Properties (Exploration I through October 31, 1986;Tenneco for periods from October 31, 1986 until November 18, 1988;Chevron with respect to all Royalty Properties for periods from November 18,1988 until October 30, 1992, and with respect to all Royalty Propertiesexcept East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene Island208 for periods from October 30, 1992 until December 1, 1994, andwith respect to the same properties except West Cameron 643 thereafter;PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, EugeneIsland 367 and Eugene/Devon Island 208 for periods from October 30, 1992until October 1, 1995, and with respect to Eugene Island 348 and EugeneIsland 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron371/381 for periods beginning on or after December 1, 1994 until May 1,2002; SONAT with respect to East Cameron 354 for periods beginning on or after October 1,1995; and Amoco with respect to Eugene Island 367 for periods beginning on orafter October 1, 1995; Amerada with respect to East Cameron 354 forperiods beginning on or after January 1, 1998; Chevron with respect toWest Cameron 643 and East Cameron 371/381 on and after May 1, 2002; andAnadarko with respect to East Cameron 354 on and after July 1, 2003.

**Note 2 — Basisof Accounting**

The accompanying unauditedfinancial information has been prepared by JPMorgan Chase Bank (formerly knownas The Chase Manhattan Bank and the successor by merger to the original name ofthe Corporate Trust, Texas Commerce Bank National Association) (“CorporateTrustee”) in accordance with the instructions to Form 10-Q and doesnot include 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 31,2003.

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; and

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

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued) (Unaudited)**

**Note 2 —Basis of Accounting (Continued)**

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 equivalentsinclude all highly liquid, short-term investments with original maturities ofthree months or less.

The decrease in reservefor future Trust expenses includes both decreases of amounts deemed necessaryby the Trustees and related distributions, as well as amounts paid from thereserve during periods when the Trust has insufficient income to pay Trustexpenses.

The Trust reviews the netoverriding royalty interest in oil and gas properties for possible impairmentwhenever events or circumstances indicate the carrying amount of the asset maynot be recoverable. If there is an indication of impairment, the Trust preparesan estimate of future cash flows (undiscounted and without interest charges)expected to result from the use of the asset and its eventual disposition. Ifthese cash flows are less than the carrying amount of the asset, an impairmentloss is recognized to write down the asset to its estimated fair value.Preparation of estimated expected future cash flows is inherently subjectiveand is based on the Corporate Trustee’s best estimate of assumptions concerningexpected future conditions. There were no write downs taken in the periodspresented.

The preparation offinancial statements requires the Trustees to make use of estimates andassumptions that affect amounts reported in the financial statements as well ascertain discounts. Actual results could differ 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 enterinto any hedging transactions on future production. Accordingly, the Statementof Financial Accounting Standards No. 133, “Accounting of DerivativeInstruments and Hedging Activities,” as amended, that was effective January 1,2001 has not had an impact on the Trust’s financial statements.

In June 2001, FASB issued SFAS No. 143, “Accountingfor Asset Retirement Obligations”, which is effective for fiscal yearsbeginning after June 15, 2002. SFAS No. 143 addresses financialaccounting and reporting for obligations associated with the retirement oftangible long-lived assets and the associated

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued) (Unaudited)**

**Note 2 —Basis of Accounting (Continued)**

assetsretirement costs. The adoption of SFAS No. 143 did not have a materialimpact on our financial position, distributable income or distributions.

**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 of futurecapital expenditures on the Royalty Properties. Net Proceeds do not includeamounts received 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.

**Note 4 — Distributionsto Unit Holders**

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

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. Royalty income to the Trust in the second quarter of 2004 was $83,857;however, 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. Asof September 30, 2004, the Trust resumed distributions as the reserve fortrust expenses had been funded.

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued) (Unaudited)**

**Note 5 — NegativeAdjustments**

Duringthe quarter ended March 31, 2004, a Working Interest Owner informed theTrust that it had made errors in prior periods which resulted in prior periodNet Proceeds being overstated. This Working Interest Owner, Chevron, which isalso the Managing General Partner, has advised the Trust that these errorsconsisted 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 — SpecialCost 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 expenditures on the RoyaltyProperties. As provided in the Conveyance, the amount of funds to be reservedis determined based on certain factors, including estimates of aggregate futureproduction costs, aggregate future Special Costs, aggregate future net revenuesand actual current net profits interest. Deposits into this account reducecurrent distributions and are placed in an escrow account and invested inshort-term certificates of deposit. Such account is herein referred to as the “SpecialCost Escrow” account. The Trust’s share of interest generated from the SpecialCost Escrow account serves to reduce the Trust’s share of allocated productioncosts. Special Cost Escrow funds will generally be utilized to pay Special Coststo the extent there are not adequate current net profits interest 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 estimated future Special Costs and there is a Net RevenuesShortfall (a calculation of the excess of estimated future costs over estimatedfuture net revenues pursuant to a formula contained in the Conveyance). Whenthere is not a Net Revenues Shortfall, amounts in the Special Cost Escrowaccount will generally be released, to the extent that Special Costs have beenincurred. Amounts in the Special Cost

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**TEL OFFSHORE TRUST**

**NOTES TO FINANCIAL STATEMENTS — (Continued) (Unaudited)**

**Note 6 —Special Cost Escrow Account (Continued)**

Escrowaccount generally will also be released when the balance in such accountexceeds 125% of estimated future Special Costs. In the first nine months of2004, there was a net release of funds from the Special Cost Escrow account.The Trust’s share of the funds released was $2,093,250. The release wasprimarily due to a decrease of $6,770,467 in projected special costs forcapital expenditures. In the first nine months of 2003, there was a net depositof funds into the Special Cost Escrow account. The Trust’s share of the fundsdeposited was $3,732,519.As of September 30, 2004, $6,497,688 remained in the Special Cost Escrowaccount.

Chevron, in its capacityas Managing General Partner, has advised the Trust that additional deposits tothe Special Cost Escrow account may be required in future periods in connectionwith other production costs, other abandonment costs, other capital expendituresand changes in the estimates and factors described above. Such deposits couldresult in a significant reduction in Royalty income in the periods in whichsuch deposits are made, including the possibility that no Royalty income wouldbe received in such periods.

**Note 7 — ReserveFor Future Trust Expenses**

The Trust made adetermination in 1998 to maintain a cash reserve equal to three times theaverage expenses of the Trust during each of the past three years to providefor future administrative expenses in connection with the winding up of theTrust. The reserve amount at December 31, 2003 was$1,364,411. Duringthe first six months of 2004, the Trust used fundsfrom the cash reserve account to pay the Trust’s general andadministrative expenses when sufficient Royalty income was not received by theTrust. As of September 30, 2004, these reserve liquidations have beenreplenished as $347,290 was withheldin the third quarter of 2004 to increase the reserve.  Thereserve amount at September 30, 2004 was $1,333,834.

**Note 8 — TexacoSettlement Agreement**

On September 21,2001, the Trust gave written demand to, and on October 11, 2001, the Trustfiled suit against TEPI as the then-current Working Interest Owner of the EastCameron 371 lease to account for its payment of the Trust’s overriding royaltyinterest in this lease. The Trust alleged that TEPI improperly reduced thepercentage of Net Proceeds payable to the Trust and improperly deducted fromGross Proceeds certain costs that the Trust believed were attributable to TEPI’sseparate operations on an offsetting lease. In connection with the foregoinglitigation, TEPI asserted a counterclaim for overpayment prior to and duringthe third quarter of 1999. TEPI claimed that these costs should have beenallocated to the Trust. During the third quarter of 2003, the Trust enteredinto a Settlement Agreement and Mutual Release with TEPI pursuant to which TEPIagreed to pay the Trust $75,000. Both of the parties agreed to file a jointmotion to dismiss all claims and counterclaims relating to the lawsuit and eachparty agreed to release the other party from all claims and counterclaimsrelating to the lawsuit.

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

**Note RegardingForward-Looking Statements**

This Form 10-Qincludes “forward-looking statements” within the meaning of Section 27A ofthe Securities Act of 1933, as amended, and Section 21E of the SecuritiesExchange Act of 1934, as amended. All statements other than statements ofhistorical facts included in this Form 10-Q are forward-lookingstatements. Although the Working Interest Owners (as defined herein) haveadvised the Trust that they believe that the expectations reflected in theforward-looking statements contained herein are reasonable, no assurance can begiven that such expectations will prove to have been correct. Important factorsthat could cause actual results to differ materially from expectations (“CautionaryStatements”) are disclosed in this Form 10-Q, including, withoutlimitation, in conjunction with the forward-looking statements included in thisForm 10-Q. A summary of certain principal risks and Cautionary Statementsis also included in the Trust’s Form 10-K for theyear ended December 31, 2003 under “Business—Principal TrustRisk Factors.” All subsequent written and oral forward-looking statementsattributable to the Trust or persons acting on its behalf are expresslyqualified in their entirety by the Cautionary Statements.

**Critical AccountingPolicies**

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; and

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

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**

**Three Months Ended September 30,2004 and 2003**

Distributions to the Unitholders for the three months ended September 30, 2004 amounted to$2,874,011 or $.604863 per Unit as compared to $1,374,065 or $.289185 per Unitfor the same period in 2003. The increase in distributable income for the thirdquarter of 2004 was primarily due to increases in both oil and gas prices, as well as a release of approximately $942,932 fromthe Special Cost Escrow Account, as described below.

Crude oil and condensate revenues decreased 21% to$8,391,210 in the third quarter of 2004 from $10,633,848 in the third quarterof 2003 due to a 37% decrease in production volumes, offset in part by a 26% increase in the averageprice of crude oil and condensate from $28.62 per barrel in the third quarterof 2003 to $36.04 in the same period in 2004. Oil volumes during the thirdquarter of 2004 totaled 232,854 

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barrels compared to 371,595 barrels ofoil produced in the third quarter of 2003. The lower oil volumes were primarilyattributable to decreases in productionon EugeneIsland 339 and Ship Shoal 182/183.

Natural gas and gas product revenuesincreased 144% to $5,700,826 in the third quarter of 2004 from $2,333,939 inthe third quarter of 2003, primarily due to a 91%increase in gas volumes to 856,414 Mcf in the third quarterof 2004 from 448,171 Mcf in the third quarterof 2003, and gas product volumesof 555,976 gallons in 2004 from 118,410 gallons in the third quarter of 2003.Additionally, the average price received for natural gas increased 24% to $6.29per Mcf in the third quarter of 2004 from $5.07 per Mcf in the third quarter of2003. The higher gas volumes were primarily due to higher production from the F-3well on Ship Shoal 182/183.

The Trust’s share ofcapital expenditures increased to$3,263,473 in the third quarter of 2004, as compared to$1,156,265 in the third quarter of 2003. The higher capital expenditures in thethird quarter of 2004 were due primarily to charges for the B-2 side-trackproject on Eugene Island 339.

For the third quarter of2004, the Trust’s share of undistributed net income was $0. Undistributed netincome represents positive Net Proceeds, generated during the respectiveperiod, that were applied to an existing loss carryforward. An undistributednet loss is carried forward and offset, in future periods, by positive NetProceeds earned by the related Working Interest Owner(s).

In the third quarter of2004, there was a net release of funds from the Special Cost Escrow Account.The Trust’s share of the funds released was $930,385, compared to a net depositof funds into the Special Cost Escrow Account of $1,225,110 by the Trust in thethird quarter of 2003. 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 “—SpecialCost Escrow Account” below.

**Nine Months Ended September 30,2004 and 2003**

Distributions to Unitholders for the nine months ended September 30, 2004 amounted to$2,874,011 or $.604863 per Unit, as compared to $3,046,252 or $.641112 per Unitfor the same period in 2003. The decrease in distributable income for the firstnine months of 2004 was primarily due to negative adjustments discussed below, partially offset by higher oiland gas prices and net releases of fundsfrom the Special Cost Escrow Account, as described below.

Crude oil and condensaterevenues decreased $13,160,880, or 46%, to $15,248,920 in the first nine monthsof 2004 as compared to $28,409,800 for the same period in 2003, due to a 58%decrease in crude oil and condensate volume to 403,237 barrels in the firstnine months of 2004 from 961,320 barrels for the same period in 2003. Therevenues and volumes for the first nine months of 2004 include negativeadjustments, as a result of the improper credits of production and revenues byChevron, totaling 295,224 barrels recorded by the Trust in the first quarter of2004. The decrease is partially offset by a 28% increase in the average priceof crude oil and condensate from $29.55 per barrel in the first nine months of2003 to $37.82 per barrel for the same period in 2004.

Natural gas and gas product revenues increased $4,173,212,or 49%, to $12,714,776 in the first ninemonths of 2004 from $8,541,564 for the same period in 2003, due to a 10%increase in the average price received for natural gas to $6.07 per Mcf in the first ninemonths of 2004 from $5.52 per Mcf in the same period of2003, and an increasein gas volumes of 113% to 1,924,360 Mcf in the first ninemonths of 2004 from 1,806,221 Mcf for the same period in 2003 and gas products volume increase of 1,636,641 to 1,919,619 gallons in the first ninemonths of 2004 compared to 282,978 gallons in the same period for 2003.The 

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productionfor the first six months of 2004 includes negative adjustments resulting fromthe improper credits of production and revenues by Chevron.

The Trust’s share ofcapital expenditures increased approximately $13,181,262, from $4,609,489 inthe first nine months of 2003 to $17,790,751 in the same period of 2004. Theincrease in capital expenditures for the first nine months of 2004 relatedprimarily to drilling of the new Ship Shoal 182/183 F-3 well and the C-20, C-21 and B-2 sidetrack wells on EugeneIsland 339 and associated platform upgrades, compared to capital expendituresfor the same period in 2003, which related primarily to the new I-4 welland some residual costs from completion of I-2 and I-3 wells on theShip Shoal 182/183 property. The Trust recorded a positive adjustment (or increase in its share of capital expenditures) of$2,026,684 in the first quarter of 2004, relating primarily to charges incurredin the fourth quarter of 2003. Adjustments to capital expenditures werebased on miscalculations and duplication of downward adjustments allocations by the Working Interest Owner onShip Shoal 182/183 during the third and fourth quarters of 2003. By contrast, the Trust recorded a ($2,014,037)balance for its share of capital expenditures due to a negative adjustment in the second quarter of 2003 relatingto the drilling of the I-4 well.  These miscalculations andduplications are reflected in the amounts provided.

The Trust’s share ofundistributed net income was $1,356,586 in the first nine months of 2004. Asdiscussed above, Net Proceeds during the second quarter of 2004 were offset bythe loss carryforward of $3,307,863 existing as of March 31,2004, resulting in a loss carryforward balance of $0 at June 30, 2004. Forthe first nine months of 2003, the Trust’s share of undistributed net incomewas $43,468.

In the first nine monthsof 2004, there was a net release of funds from the Special Cost Escrow Account.The Trust’s share of the funds released was $2,093,250. In the first ninemonths of 2003, there was a net deposit of funds into the Special Cost Escrowaccount. The Trust’s share of the funds deposited was $3,740,198.As of September 30, 2004, $6,497,688 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 “—SpecialCost Escrow Account” below.

**Reserve for FutureTrust Expenses**

Inaccordance with the provisions of the Trust Agreement, generally all Royaltyincome received by the Trust, net of Trust general and administrative expensesand any cash reserves established for the payment of contingent or futureobligations of the Trust, are distributed currently to the Unit holders. In thefirst quarter of 1998, the Trust determined that the Trust’s cash reserve wassufficient at that time to provide for future administrative expenses inconnection with the winding up of the Trust. The Trust determined that a cashreserve equal to three times the average expenses of the Trust during each ofthe past three years was sufficient at this time to provide for futureadministrative expenses in connection with the winding up of the Trust. Thereserve amount for 2003 was $1,364,411. Duringthe first six months of 2004, the Trust used fundsfrom the cash reserve the Trust’s cash reserve account to paythe Trust’s general and administrative expenses, when sufficient Royalty incomewas not received by the Trust. As ofSeptember 30, 2004 those reserve liquidations havebeen replenished as$347,290 was withheld in the third quarter of 2004 to increase the reserve. Thereserve amount at September 30, 2004 was $1,333,834.

**Other**

The amount of cash distributed by the Trust isdependent on, among other things, the sales prices and quantities of oil andgas produced from the Royalty Properties as well as capital expenditures by the

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WorkingInterest Owners that may or may not be included in the Special Cost Escrowaccount. It should be noted that substantial uncertainties exist with regard tofuture oil and gas prices, which are subject to material fluctuations due tochanges in production levels and pricing and other actions taken by majorpetroleum producing nations, as well as the regional supply and demand for oiland gas, weather, industrial growth, conservation measures, competition andother variables.

**OperationalReview**

**Three Months Ended September 30, 2004 and 2003**

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

Ship Shoal 182/183 crude oil revenues increased from$4,528,163 in the third quarter of 2003 to $4,879,287 in the third quarter of2004, primarily due to a increase in the average crude oil price from $27.70per barrel in the third quarter of 2003 to $36.73 per barrel for the sameperiod in 2004. The increase was partially offset by a decrease in crude oilproduction from 163,498 barrels in the third quarterof 2003 to 132,838 barrels in the third quarter of 2004. Gas revenues increasedfrom $690,072 in the third quarter of 2003 to $3,837,637 in the third quarterof 2004, primarily due to an increase in both production and prices. Gasvolumes increased from 135,252 Mcf in the third quarter of 2003 to 608,639 Mcfin the third quarter of 2004. The average natural gas sales price increasedfrom $5.23 per Mcf in the third quarter of 2003 to $6.31 per Mcf in the thirdquarter of 2004. The increase in gas volumes was primarily due to strongproduction from the F-3 well that came online in January of 2004.Capital expenditures decreased from $945,493 in the third quarter of 2003 to$190,336 in the third quarter of 2004. Operating expenses decreased slightlyfrom $409,810 in the third quarter of 2003 to $403,157 for the same period in2004.

Eugene Island 339 crude oil revenues decreased from$5,852,916 in the third quarter of 2003 to $3,388,028 in the third quarter of2004, primarily due to a significant decrease in production. Crude oilproduction decreased from 199,088 barrels in the third quarter of 2003 to96,577 barrels in the third quarter of 2004, primarily due to a shut in for eightdays in June for a rig move, and natural production declines on the C-19 well after aninitial strong start andon the C-5 well due to the well being choked backbecause of sand production. The average price of crude oil increased from$29.40 per barrel in the third quarter of 2003 to $35.08 in the third quarterof 2004. Gas revenues increased from $629,719 in the third quarter of 2003 to$1,086,662 in the third quarter of 2004, primarily due to a production increasefrom 147,486 Mcf in the third quarter of 2003 to 172,307 in the third quarterof 2004. The average natural gas sales price increased from $4.27 per Mcf inthe third quarter of 2003 to $6.31 per Mcf in the third quarter of 2004.Capital expenditures increased to $3,021,559 in the third quarter of 2004 from$141,578 in the third quarter of 2003 due to charges for the B-2side-track project. Operating expenses increased from $136,700 in the thirdquarter of 2003 to $314,959 in the third quarter of 2004.

West Cameron 643 gas revenues decreased from $720,459in the third quarter of 2003 to $326,340 in the third quarter of 2004,primarily due to a decrease in gas volume from 133,060 Mcf in the third quarterof 2003 to 53,240 Mcf in the third quarter of 2004, and partially offset by aincrease in the average price received for natural gas from $5.41 per Mcf inthe third quarter of 2003 to $6.13 in the same period for 2004. The decrease ingas volumes was due primarily to a natural production decline. Operatingexpenses decreased from $162,336 in the third quarter of 2003 to $64,731 forthe same period in 2004. Capital expenditures decreased from $27,238 in the thirdquarter of 2003 to $5,312 in the third quarter of 2004.

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East Cameron 371/381 crudeoil revenues increased slightly from $10,491 in the third quarter of 2003 to$10,884 in the third quarter of 2004, primarily due to an increase in theaverage price received of $30.76 per barrel in the third quarter of 2003 to $40.92per barrel in the third quarter of 2004. The price increase was partiallyoffset by a decrease in crude oil production from 341 barrels in the thirdquarter of 2003 to 266 barrels in the same period in 2004. Gas revenuesdecreased slightly from $32,347 in the third quarter of 2003 to $29,453 in thethird quarter of 2004. This decrease was primarily due to a decrease in gasvolumes from 6,135 Mcf in the third quarter of 2003 to 5,032 Mcf in the third quarter of2004. This volume decrease was partially offset by an increase in the averagenatural gas sales price from $5.27 per Mcf in the third quarter of 2003 to$5.85 per Mcf in the third quarter of 2004. Operating expenses increased from$4,267 in the third quarter of 2003 to $6,242 in the third quarter of 2004.Capital expenses decreased from $611 in the third quarter of 2003 to $173 inthe third quarter of 2004.

**Nine Months Ended September 30,2004and 2003**

*Volumes and dollaramounts discussed below represent amounts recorded by the Working Interest Ownersunless otherwise specified.*

Ship Shoal 182/183 crude oil revenues decreased from$13,809,481 in the first nine months of 2003 to $11,586,941 in the first ninemonths of 2004, primarily due to a decline in crude oil production from 459,736barrels in the first nine months of 2003 to 336,072 barrels in the first ninemonths of 2004, which includes a negative retroactive adjustment of 44,214barrels relating to the fourth quarter of 2003 discussed below. The decrease was partiallyoffset by an increase in the average crude oil price from $30.04per barrel in the first nine months of 2003 to $34.48 per barrel for the sameperiod in 2004. Gas revenues increased from $2,225,994 in the first nine monthsof 2003 to $8,254,336 in first nine months of 2004 primarily due to asignificant increase in gas volumes from 408,452 Mcf in the first nine monthsof 2003 to 1,369,788 Mcf for the same period in 2004. Gas volumes increasedprimarily as a result of higher production from the F-3 well. The average natural gas sales priceincreased from $5.45 per Mcf in the first nine months of 2003 to $6.03 in the first nine months of2004. Capital expenditures increased from $4,137,767 in the first nine monthsof 2003 to $8,040,549 in the same period of 2004, primarily due to $6.3 millionof capital expenditures made to complete the F-3 drilling project.Operating expenses increased from $1,172,953 for the first nine months of 2003to $2,110,160 for the first nine months of 2004.

Eugene Island 339 crude oil revenues decreased from$13,884,063 in the first nine months of 2003 to $3,728,107 in the first ninemonths of 2004, primarily due to a decrease in volumes from 478,395 barrels inthe first nine months of 2003 to 70,198 barrels in the first nine months of2004, which gives effect to a negative retroactive adjustment of 236,650barrels relating to the period of January through October 2003 forimproper credits of production and revenues discussed below. The decrease in productionwas partially offset by the increase in average crude oil price from $29.02 perbarrel in the first nine months of 2003 to $31.53 per barrel in the first ninemonths of 2004. Gas revenues decreased from $2,802,367 in the first nine monthsof 2003 to $2,270,350 in the first nine months of 2004, primarily due to adecrease in production from 533,093 Mcf for the first nine months of 2003 to354,018 Mcf for the same period in 2004. Capital expenditures increased from$243,039 in the first nine months of 2003 to $9,673,067in the first nine months of 2004. The increase was due primarily to variouscapital projects that were completed in the first six months of 2004, includingthe C-20 and C-21 drilling projects that cost approximately $1.5million and $3.3 million, respectively;  upgradeto the C platform facilities that cost approximately $517,000; and the

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3Q 04 B-2 sidetrackproject costing $3.2 million. Operating expenses increasedfrom $357,379 for the first nine months of 2003 to $1,260,322 for the firstnine months of 2004.

West Cameron 643 gas revenues decreased from$2,710,994 in the first nine months of 2003 to $804,828 in the first ninemonths of 2004, primarily due to a decrease in gas volumes from 476,615 Mcf inthe first nine months of 2003 to 144,043 Mcf for the same period in 2004. Theaverage natural gas sales price decreased from $5.69 per Mcf in the first ninemonths of 2003 to $5.59 per Mcf in the first ninemonths of 2004. Operating expenses decreased from $512,390 in the first ninemonths of 2003 to $218,875 for the first nine months of 2004. Capitalexpenditures decreased from $159,057 in the first nine months of 2003 to $7,893in the first nine months of 2004.

East Cameron 371/381 crude oil revenues decreased from$61,808 in the first nine months of 2003 to $28,938 in the first nine months of2004 due in part to a decrease in crude oil production from 1,929 barrels inthe first nine months of 2003 to 794 barrels in the first nine months of 2004.The decrease in production was offset by an increase in the average price ofcrude oil from $32.04 per barrel in the first nine months of 2003 to $36.45 per barrel for the sameperiod in 2004. Gas revenues decreased from $149,358 in the first nine monthsof 2003 to $78,930 in the first nine months of2004, due in part to a decrease in gas volumes from 29,988 Mcf in the firstnine months of 2003 to 14,601 Mcf in the first nine months of 2004. Thedecrease in gas volumes was offset by an increase in the average natural gassales price from $4.98 per Mcf in the first nine months of 2003 to $5.41per Mcf in the first nine months of 2004. Operating expenses increased from$21,686 in the first nine months of 2003 to $23,313 in the first nine months of2004. Capital expenditures decreased from $5,697 in the first nine months of2003 to $1,496 in the first nine months of 2004.

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, has advised the Trust that these errors consisted 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 Escrow account adjustment, were $10,911,175 or a$2,727,521 increase to $3,307,628 in the losses to be carried forward andnetted against future Net Proceeds earned by the Trust on Royalty Propertiesoperated by this Working Interest Owner as of March 31, 2004. In thesecond quarter of 2004, Net Proceeds were sufficient to fully offset theloss carryforward of $3,307,628, resulting in no further loss carryforward.

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**Future Net Revenues and Termination of the Trust**

Based on a reserve studyprovided to the Trust by DeGolyer and MacNaughton, independent petroleumengineers, it was estimated that as of October 31, 2003future net revenues attributable to the Trust’s royalty interests approximated$24.8 million. Such reserve studyalso indicates that approximately 75% of the future net revenuesfrom the Royalty Properties are expected to be received by the Trust during thenext three years. In addition, because the Trust will terminate in the eventestimated future net revenues fall below $2 million, it would be possible forthe Trust to terminate even though some or all of the Royalty Propertiescontinued to have remaining productive lives. Upon termination of the Trust,the Trustees will sell for cash all of the assets held in the Trust estate andmake a final distribution to Unit holders of any funds remaining after allTrust liabilities have been satisfied. The estimates of future net revenuesdiscussed above are subject to large variances from year to year and should notbe construed as exact. There are numerous uncertainties present in estimatingfuture net revenues for the Royalty Properties. The estimate may vary dependingon changes in market prices for crude oil and natural gas, the recoverablereserves, annual production and costs assumed by DeGolyer and MacNaughton. Inaddition, future economic and operating conditions as well as results of futuredrilling plans may cause significant changes in such estimate. The discussionset forth above is qualified in its entirety by reference to the Trust’s 2003Annual Report on Form 10-K. The Form 10-K is available upon requestfrom 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 2004, there was a net release of funds from the Special EscrowAccount. The Trust’s share of the funds released was $2,093,250. The release wasprimarily to a result of a decrease of $6,770,487 inprojected specialcosts for capital expenditures. In the first nine months of2003, there was a net deposit of funds into the Special Cost Escrow Account.The Trust’s share of the funds deposited was $3,740,198. As of September 30,2004, $6,497,688 remained in the Special Cost Escrow Account.

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Chevron, in its capacityas Managing General Partner, has advised the Trust that additional deposits tothe Special Cost Escrow Account may be required in future periods in connectionwith other production costs, other abandonment costs, other capitalexpenditures and changes in the estimates and factors described above. Suchdeposits, if made, could result in a significant reduction in Royalty income inthe periods in which such deposits are made, including the possibility that noRoyalty income would be received in such periods.

**Overview ofProduction, Prices and Net Proceeds**

Thefollowing schedule provides a summary of the volumes and weighted averageprices for crude oil and condensate and natural gas recorded by the WorkingInterest Owners for the Royalty Properties, as well as the Working InterestOwners’ calculations of the net proceeds and the royalties paid to the Trustduring the periods indicated. Net proceeds due to the Trust are calculated foreach three month period commencing on the first day of February, May, August andNovember.
| ** **                                                   | ** ** | **Royalty Properties  Three Months Ended  September 30,**(1) | ** ** |
|--------------------------------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **2004**                                                                         | ** ** | **2003** | ** ** |
| Crude oil and  condensate (bbls)                             |       | 232,854                                                                          |       | 371,595 |   |
| Natural gas and  gas products (Mcf)                          |       | 856,414                                                                          |       | 465,088 |   |
| Crude oil and  condensate average price, per bbl             |       | $                                                                                | 36.04      |   | $ | 28.62 |   |
| Natural gas  average price, per Mcf (excluding gas products) |       | $                                                                                | 6.29       |   | $ | 5.07 |   |
| Crude oil and  condensate revenues                           |       | $                                                                                | 8,391,210  |   | $ | 10,633,848 |   |
| Natural gas and  gas products revenues                       |       | 5,700,826                                                                        |       | 2,333,939 |   |
| Production  expenses                                         |       | (1,353,519                                                                       | )          | (1,138,123 | ) |
| Capital  expenditures                                        |       | (3,263,473                                                                       | )          | (1,156,265 | ) |
| Undistributed Net  Income(2)                                 |       | 0                                                                                |       | 0 |   |
| Refund  Of/(Provision for) escrowed special costs            |       | 3,790,660                                                                        |       | (4,900,439 | ) |
| **Net  Proceeds**                                            |       | 13,265,704                                                                       |       | 5,772,960 |   |
| Royalty interest                                             |       | x25                                                                              | %          | x25 | % |
| Partnership share                                            |       | 3,316,426                                                                        |       | 1,443,240 |   |
| Trust interest                                               |       | x99.99                                                                           | %          | x99.99 | % |
| Trust share                                                  |       | $                                                                                | 3,316,095  |   | $ | 1,443,095 |   |

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(1)          The amounts for thethree months ended September 30, 2004 and 2003 represent actual productionfor the periods May 2004 through July 2004, and May 2003 throughJuly 2003, respectively.

(2)          Undistributed net incomerepresents positive Net Proceeds, generated during the respective period, thatwere applied to an existing loss carryforward. As of September 30, 2004,the loss carryforward was $0.

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| ** **                                                      | ** ** | **Royalty Properties  Nine Months Ended  September 30,**(1) | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| ** **                                                      | ** ** | **2004**                                                                        | ** ** | **2003** | ** ** |
| Crude oil and  condensate (bbls)(2)                             |       | 403,237                                                                         |       | 961,320 |   |
| Natural gas and  gas products (Mcf)(3)                          |       | 1,924,360                                                                       |       | 1,563,670 |   |
| Crude oil and  condensate average price, per bbl(2)             |       | $                                                                               | 31.01      |   | $ | 29.55 |   |
| Natural gas  average price, per Mcf (excluding gas products)(3) |       | $                                                                               | 6.07       |   | $ | 5.52 |   |
| Crude oil and  condensate revenues(2)                           |       | $                                                                               | 15,248,920 |   | $ | 28,409,800 |   |
| Natural gas and  gas products revenues(3)                       |       | 12,714,775                                                                      |       | 8,541,564 |   |
| Production  expenses(4)                                         |       | (5,145,996                                                                      | )          | (3,413,783 | ) |
| Capital  expenditures(4)                                        |       | (17,790,751                                                                     | )          | (4,609,489 | ) |
| Undistributed Net  Loss (Income)(5)                             |       | (1,356,586                                                                      | )          | (43,468 | ) |
| Refund of/  (Provision for) escrowed special costs              |       | 9,930,800                                                                       |       | (14,962,460 | ) |
| **Net  Proceeds**                                               |       | 13,601,163                                                                      |       | 13,922,164 |   |
| Royalty interest                                                |       | x25                                                                             | %          | x25 | % |
| Partnership share                                               |       | 3,400,291                                                                       |       | 3,480,541 |   |
| Trust interest                                                  |       | x99.99                                                                          | %          | x99.99 | % |
| Trust share                                                     |       | $                                                                               | 3,399,952  |   | $ | 3,480,192 |   |

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(1)          The amounts for the nine months ended September 30, 2004 and 2003 represent actual production for the periods November 2003through July 2004, and November 2002 through July 2003, respectively.

(2)   Includesnegative volume adjustments of 295,224 bbls for the nine months ended September 30,2004. Exclusive of these adjustments, volumes would have been 698,461 bbls.Excluding the impact of these adjustments crude oil and condensate averageprice per bbl would have been $33.62. Excluding the impact of these adjustmentscrude oil and condensate revenues would have been $23,481,291.

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

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

(5)          Undistributed net lossrepresents negative Net Proceeds generated during the respective period. Anundistributed net loss is carried forward and offset, in future periods, bypositive Net Proceeds earned by the related Working Interest Owner(s). Undistributednet income represents positive Net Proceeds, generated during the respectiveperiod that was applied to an existing loss carryforward. In the quarter ended September 30,2004, Net Proceeds were offset by the loss carryforward of $3,307,628 existingas of March 31, 2004. At September 30, 2004, there was no additionalloss carryforward.

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**Item 3. Quantitative and Qualitative Disclosure AboutMarket Risk**

No material changes haveoccurred since our Annual Report on Form 10-K for the year-ended December 31,2003. Reference is also made to Note 2 of the Notes to FinancialStatements included in Item 1 of this Form 10-Q.

**Item 4. Controls and Procedures.**

*Evaluationof disclosure controls and procedures.**  *Mike Ulrich, as Trust Officer ofthe Corporate Trustee, has concluded that the disclosure controls andprocedures of the Trust are effective, while noting certain limitations ondisclosure controls and procedures as set forth below.

Due to thecontractual arrangements of (i) the Trust Agreement, (ii) thePartnership Agreement and (iii) the rights of the Partnership under theConveyance regarding information furnished by the working interest owners,there are certain potential weaknesses that may limit the effectiveness ofdisclosure controls and procedures established by the Corporate Trustee or itsemployees and their ability to verify the accounting of certain financialinformation. The contractual limitations creating potential weaknesses indisclosure controls and procedures may be deemed to include:

·       TheWorking Interest Owners alone control (i) historical operating data,including production volumes, marketing of products, operating and capitalexpenditures, environmental and other liabilities, the effects of regulatorychanges and the number of producing wells and acreage, (ii) plans forfuture operating and capital expenditures, (iii) geological data relatingto reserves and (iv) information relating to projected production. Whilethe Corporate Trustee requests material information for use in periodic reportsas part of its disclosure controls and procedures, neither the Trustees nor themanaging general partner of the Partnership (to the extent the managing generalpartner is not also the Working Interest Owner) control this information, andthey rely entirely on the Working Interest Owners to provide accurate andtimely information when requested for use in the Trust’s periodic reports.

·       TheTrustees, including the Corporate Trustee, rely on information provided by themanaging general partner of the Partnership that is collected by the managinggeneral partner from the Working Interest Owners. While the Trustees mayrequest information through the managing general partner, the Conveyancetogether with the Partnership Agreement gives only the managing general partnerof the Partnership, as the Royalty Owner, the actual authority and discretionto request and receive financial information regarding the Royalty Propertiesfrom the Working Interest Owners. While the Corporate Trustee requests materialinformation for use in periodic reports as part of its disclosure controls andprocedures, the Trustees, including the Corporate Trustee, generally do nothave any direct contact with Working Interest Owners, other than the managinggeneral partner, and rely on the managing general partner of the Partnership torequest and obtain information deemed material by the Trustees.

·       Underthe terms of the Trust Agreement, the Trustees, including the Corporate Trustee,are entitled to, and in fact do rely, upon certain experts in good faith,including (i) the independent reserve engineer with respect to the annualreserve report, which includes projected production, operating expenses andcapital expenses, and (ii) the independent auditors with whom they havecontracted with respect to reviews or audits of financial data provided by themanaging general 

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partner and workinginterest owners. Other than contracting independent auditors and reviewing themanaging general partner’s statements on a quarterly basis, the Trustees makeno independent or direct verification of this financial information. TheConveyance also restricts access to and the review of confidential reserve dataprovided by working interest owners to the independent reserve engineer. Whilethe Trustees have no reason to believe their reliance upon experts isunreasonable, this reliance on experts and restricted access to information maybe viewed as a weakness.

The Trustees do not intend to expand their responsibilitiesbeyond those permitted or required by the Trust Agreement and those requiredunder applicable law.

Information regarding operations provided by theWorking Interest Owners, including ChevronTexaco, has been subject to errorsand adjustments, some of which have been significant. These include errors andadjustments that are reflected in this report and other historical reports.Accordingly, while the Trustees make diligent inquiries and request changes tointernal controls of the Working Interest Owners when errors are identified,the Trustees cannot assure Unit holders that other errors or adjustments byWorking Interest Owners, whether historical or future, will not affect futureRoyalty income and distributions by the Trust.

*Changesin Internal Control Over Financial Reporting.**  *During the three months ended September 30,2004, 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 12, 2004

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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