**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 March 31, 2007**                                                                     |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **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 or other  jurisdiction of              |   | I.R.S. Employer      |
| incorporation or  organization)               |   | Identification  No.) |
| **The Bank of New York Trust Company , N.A.** |   | ** **           |
| **919  Congress Avenue**                      |   | ** **           |
| **Austin,  Texas**                            |   | **78701**            |
| (Address of  principal executive offices)     |   | (Zip Code)           |

 

Registrant’s telephonenumber, including area code: **(800) 852-1422**

Indicate by check mark whether the registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of theSecurities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the registrant was required to file such reports), and(2) has been subject to such filing requirements for the past 90 days.Yes x    No o

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer. Seedefinition of “accelerated filer or large accelerated filer” in Rule 12b-2of the Exchange Act.

(Check one):    LargeAccelerated Filer o    AcceleratedFiler o    Non-acceleratedfiler x

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

Indicatethe number of shares outstanding of each of the issuer’s classes of commonstock, as of the latest practicable date. As of May 15, 2007—4,751,510Units of Beneficial Interest in TEL Offshore Trust.

 

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**NOTE REGARDINGFORWARD-LOOKING STATEMENTS**

This Form 10-Q includes “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934,as amended. All statements other than statements of historical facts includedin this Form 10-Q are forward-looking statements. Although theWorking Interest Owners (as defined herein) have advised the Trust that theybelieve that the expectations reflected in the forward-looking statementscontained herein are reasonable, no assurance can be given that suchexpectations will prove to have been correct. Important factors that couldcause actual results to differ materially from expectations (“CautionaryStatements”) are disclosed in this Form 10-Q, including, withoutlimitation, in conjunction with the forward-looking statements includedin this Form 10-Q. A summary of certain principal risks andCautionary Statements is also included in the Trust’s Annual Report on Form 10-Kfor the year ended December 31, 2006. under Part I, Item 1A “RiskFactors.” 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.

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**PART I—FINANCIAL INFORMATION**

**Item 1.**                        FinancialStatements.

**TELOFFSHORE TRUSTSTATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS(Unaudited)**
|                                                                                                                                           | ** ** | **March 31,  2007** | ** ** | **December 31,  2006** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|-----------------------------|------------|
| **Assets**                                                                                                                                | ** ** | ** **               | ** ** |                        | ** ** | ** ** |   |
| Cash and cash  equivalents                                                                                                                |       | $                        | 3,045,467  |                        |       | $ | 3,321,587 | ** ** |   |
| Net overriding  royalty interest in oil and gas properties, net of accumulated amortization  of $28,218,122 and $28,214,149, respectively |       | 49,533                   |       |                        | 53,506     | ** ** |   |
| Total assets                                                                                                                              |       | $                        | 3,095,000  |                        |       | $ | 3,375,093 | ** ** |   |
| **Liabilities  and Trust Corpus**                                                                                                         | ** ** | ** **               | ** ** |                        | ** ** | ** ** |   |
| Distribution  payable to Unit holders                                                                                                     |       | $                        | 1,167,574  |                        |       | $ | 1,697,721 | ** ** |   |
| Reserve for  future Trust expenses                                                                                                        |       | 1,877,893                |       |                        | 1,623,866  | ** ** |   |
| Commitments and  contingencies                                                                                                            |       |                     |       |                        |       | ** ** |   |
| Trust corpus  (4,751,510 Units of beneficial interest authorized and outstanding)                                                         |       | 49,533                   |       |                        | 53,506     | ** ** |   |
| Total liabilities and  Trust corpus                                                                                                       |       | $                        | 3,095,000  |                        |       | $ | 3,375,093 | ** ** |   |

 

**STATEMENTS OFDISTRIBUTABLE INCOME(Unaudited)**

| ** **                                                | ** ** | **Three Months Ended  March 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                                | ** ** | **2007**                                         | ** ** | **2006** | ** ** |
| Royalty income                                            |       | $                                                | 1,516,684  |   | $ | — |   |
| Interest income                                           |       | 18,039                                           |       | 4,792 |   |
|                                                      |       | 1,534,723                                        |       | 4,792 |   |
| (Increase)/decrease  in reserve for future Trust expenses |       | (254,027                                         | )          | 164,390 |   |
| General and  administrative expenses                      |       | (113,122                                         | )          | (169,182 | ) |
| Distributable  income                                     |       | $                                                | 1,167,574  |   | $ | — |   |
| Distributions per Unit  (4,751,510 Units)                 |       | $                                                | .245727    |   | $ | .000000 |   |

 

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

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

| ** **                                       | ** ** | **Three Months Ended  March 31, ** | ** ** |
|--------------------------------------------------|------------|--------------------------------------------------------|------------|
| ** **                                       | ** ** | **2007**                                               | ** ** | **2006** | ** ** |
| Trust corpus,  beginning of period               |       | $                                                      | 53,506     |   | $ | 64,069 |   |
| Distributable  income                            |       | 1,167,574                                              |       | — |   |
| Distribution  payable to Unit holders            |       | 1,167,574                                              |       | — |   |
| Amortization of  net overriding royalty interest |       | (3,973                                                 | )          | (2,489 | ) |
| Trust corpus, end of  period                     |       | $                                                      | 49,533     |   | $ | 61,580 |   |

 

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

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**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 TennecoExploration, Ltd. (“Exploration I”) located offshore Louisiana to thePartnership and issuing certificates evidencing units of beneficial interest inthe Trust (“Units”) in liquidation and cancellation of Tenneco Offshore’scommon stock.

On October 31, 1986, Exploration I was dissolvedand the oil and gas properties of Exploration I were distributed toTenneco subject to the Royalty. Tenneco, who was then serving as the ManagingGeneral Partner of the Partnership, assumed the obligations of Exploration I,including its obligations under the instrument conveying the Royalty to thePartnership (the “Conveyance”). The dissolution of Exploration I had noimpact on future cash distributions to holders of units of beneficial interest.

On November 18, 1988, Chevron U.S.A., Inc. (“Chevron”)acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco,including all of the Royalty Properties. As a result of the acquisition,Chevron replaced Tenneco as the Working Interest Owner and Managing GeneralPartner of the Partnership. Chevron also assumed Tenneco’s obligations underthe Conveyance.

On October 30, 1992, PennzEnergy Company (“PennzEnergy”)(which merged with and into Devon Energy Production Company L.P. effective January 1,2000) acquired certain oil and gas producing properties from Chevron, includingfour of the Royalty Properties. The four Royalty Properties acquired byPennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 andEugene Island 208. As a result of such acquisition, PennzEnergy replacedChevron as the Working Interest Owner of such properties on October 30,1992. PennzEnergy also assumed Chevron’s obligations under the Conveyance withrespect to these properties.

On December 1, 1994, Texaco Exploration andProduction Inc. (“TEPI”) acquired two of the Royalty Properties fromChevron. The Royalty Properties acquired by Texaco were West Cameron 643 andEast Cameron 371. As a result of such acquisition, 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 andalso assumed PennzEnergy’s obligations under the Conveyance with respect tothese properties.

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

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obligations under theConveyance with respect to such property. In October 1998, Amerada HessCorporation (“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 this 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. The abandonment obligations for Eugene Island 348have been assumed by Maritech Resources, Inc. effective January 1,2005.

On October 9, 2001, a wholly owned subsidiary ofChevron Corporation, a Delaware corporation, merged (the “Merger”) with andinto Texaco Inc., a Delaware corporation (“Texaco”), pursuant to anAgreement and Plan of Merger, dated as of October 15, 2000. As a result ofthe Merger, Texaco Inc. became a wholly owned subsidiary of ChevronCorporation, and Chevron Corporation changed its name to “ChevronTexacoCorporation” in connection with the Merger. Effective May 9, 2005,ChevronTexaco Corporation changed its name to Chevron Corporation. Accordingly,the properties referred to herein by Chevron and Texaco are each now controlledby subsidiaries of Chevron Corporation.

On May 1, 2002, TEPI assigned all of itsinterests in West Cameron 643 and East Cameron 371 to Chevron. Accordingly,pursuant to the Conveyance of the Royalty Properties, net proceeds will becalculated 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 the Royalty from Amerada effective April 1, 2003. As aresult of this transaction, Anadarko replaced Amerada as the Working InterestOwner of East Cameron 354 effective July 1, 2003 and also assumed Amerada’sobligations under the conveyance with respect to this property.

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

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

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

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Eugene Island 348 andEugene Island 208 thereafter; TEPI with respect to West Cameron 643 and EastCameron 371 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; 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 until July 1, 2003; Chevronwith respect to West Cameron 643 and East Cameron 371 on and after May 1,2002; Anadarko with respect to East Cameron 354 on and after July 1, 2003until October 1, 2004; and Apache with respect to East Cameron 354 after October 1,2004).

The Trust is currentlyadministered by The Bank of New York Trust Company, N.A., which succeededJPMorgan Chase Bank, N.A. as the Corporate Trustee, effective October 2,2006 pursuant to an agreement under which The Bank of New York acquiredsubstantially all of the Corporate Trust business of JPMorgan Chase (formerlyknown as The Chase Manhattan Bank), and Daniel O. Conwill, IV,Gary C. Evans and Jeffrey S. Swanson (“Individual Trustees”), astrustees (“Trustees”).

**Note 2—Basisof Accounting**

The accompanying unaudited financial information hasbeen prepared by The Bank of New York Trust Company, N.A. (“CorporateTrustee”) in accordance with the instructions to Form 10-Q. Theaccompanying financial information is prepared on a comprehensive basis ofaccounting other than accounting principles generally accepted in the UnitedStates of America. The Corporate Trustee and the individual trustees(collectively, the “Trustees”) believe that the disclosures are adequate tomake the information presented not misleading. The information furnishedreflects all adjustments which are, in the opinion of the Trustees, necessaryfor a fair presentation of the results for the interim periods presented. Thefinancial information should be read in conjunction with the financialstatements and notes thereto included in the Trust’s Annual Report on Form 10-Kfor the year ended December 31, 2006.

The financial statements of the Trust are prepared onthe following basis:

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

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

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

This manner of reporting income and expenses isconsidered to be the most meaningful because the quarterly distributions toUnit holders are based on net cash receipts received from the Working InterestOwners. The financial statements of the Trust differ from financial statementsprepared in accordance with generally accepted accounting principles, because,under such principles, Royalty income and Trust general and administrativeexpenses for a quarter would be recognized on an accrual basis. In addition, 

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amortization of the netoverriding royalty interest, which is calculated on a units-of-productionbasis, is charged directly to Trust corpus since such amount does not affectdistributable income.

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

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

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

The Special Cost Escrow account (Note 5) isestablished for the future costs to be incurred to plug and abandon wells,dismantle and remove platforms, pipelines and other production facilites 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,applicable taxes other than income taxes, and a Special Cost Escrow account.The Special Cost Escrow account (See Note 5) is 

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establishedfor the future costs to be incurred to plug and abandon wells, dismantle andremove platforms, pipelines and other production facilities, and for theestimated amount of future capital expenditures on the Royalty Properties. NetProceeds do not include amounts received by the Working Interest Owners asadvance gas payments, “take-or-pay” payments or similar payments unless anduntil such payments are extinguished or repaid through the future delivery ofgas.

**Note 4—Distributionsto 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 2005, HurricaneKatrina and Hurricane Rita caused significant damage to various platforms andthird-party transportation systems which resulted in oil and gas productiondelays in the Royalty Properties. During 2006 several of the platforms andfacilities on the Royalty Properties were restored; however, certain projectsremain to be completed during 2007 to increase production to pre-hurricanelevels. The Trust may have to fund its share of project costs and other relatedexpenditures that are not covered by insurance of the operator of the RoyaltyProperties. Further delays in repairs on third-party transportation systems maycontinue to limit production. Additionally, the extensive damage caused bythese hurricanes has led to significant demand for services and supplies forrepairs in the offshore Gulf of Mexico, which has increased current and futurelevels of expenditures. The reduced oil and gas production and increased costsreduced the cash income distributions to unitholders significantly during 2006and may continue to affect cash income distributions during a portion or all of2007. During the fourth quarter 2006, the Trust resumed distributions. The fourthquarter distribution of $1.7 million was paid on January 11, 2007. OnMarch 30, 2007, the Trust announced its first quarter distribution ofapproximately $1.2 million.

**Note 5—Special CostEscrow Account**

The Special Cost Escrow is an account of the WorkingInterest Owners, and it is described herein for informational purposes only.The Conveyance provides for the reserve of funds for estimated future “SpecialCosts” of plugging and abandoning wells, dismantling platforms and other costsof abandoning the Royalty Properties, as well as for the estimated amount offuture drilling projects and other capital expenditures on the RoyaltyProperties. As provided in the Conveyance, the amount of funds to be reservedis determined based on certain factors, including estimates of aggregate futureproduction costs, aggregate future Special Costs, aggregate future net revenuesand actual current net profits interest. Deposits into this account reducecurrent distributions and are placed in an escrow account and invested inshort-term certificates of deposit. Such account is herein referred to as the “SpecialCost Escrow” account. The Trust’s share of interest generated from the SpecialCost Escrow account serves to reduce the Trust’s share of allocated productioncosts. Special Cost Escrow funds will generally be utilized to pay SpecialCosts to the extent there are not adequate current net profits interest to paysuch costs. Special Costs that 

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have been paid are nolonger included in the Special Cost Escrow calculation. Deposits to the SpecialCost Escrow account will generally be made when the balance in the Special CostEscrow account is less than 125% of estimated future Special Costs and there isa Net Revenues Shortfall (a calculation of the excess of estimated future costsover estimated future net revenues pursuant to a formula contained in theConveyance). When there is not a Net Revenues Shortfall, amounts in the SpecialCost Escrow account will generally be released, to the extent that SpecialCosts have been incurred. Amounts in the Special Cost Escrow account will alsobe released when the balance in such account exceeds 125% of estimated futureSpecial Costs. In the first quarter of 2007, there was a net deposit of fundsto the Special Cost Escrow account of approximately $811,000. As of March 31,2007, $7,648,195 remained in the Special Cost Escrow account. The funds held inthe Special Cost Escrow account are not reflected in the financial statementsof the Trust.

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

**Note 6—ReserveFor Future Trust Expenses**

The Trust made a determination in 1998 to maintain acash reserve equal to approximately three times the average expenses of theTrust during each of the past three years to provide for future administrativeexpenses in connection with the winding up of the Trust. During the firstquarter of 2007, the Trust increased its reserve by $254,027 for a reservebalance of $1,877,893 as of March 31, 2007. The reserve amount at March 31,2006 was $1,199,813.

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

**Critical AccountingPolicies**

The financial statements of the Trust are prepared onthe following basis:

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

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

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

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

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

**Financial Review**

**Three Months Ended March 31,2007 and 2006**

There were distributions of $1,167,574 or $0.245727per Unit to the Unit holders for the three months ended March 31, 2007 ascompared to no distributions for the same period in 2006. There was nodistributable income for the first quarter of 2006 primarily as a result ofdamages caused to the royalty properties by Hurricanes Rita and Katrinadiscussed below in “Operational Review” and a required deposit to the SpecialCost Escrow account.

Crude oil and condensate revenues increased$4,062,307, or 72%, to $9,699,483 in the first quarter of 2007 as compared to$5,637,176  in the first quarter of 2006,due to production coming back online after hurricane-related damages. Theaverage price of crude oil and condensate increased from $56.60 per barrel inthe first quarter of 2006 to $60.62 per barrel in the first quarter of 2007, or7%.

Gas revenues increased $1,952,356, or 349%, to$2,512,488 in the first quarter of 2007 from $560,132 in the first quarter of2006, due to an increase in gas volumes of 341% to 371,262 Mcf in the firstquarter of 2007 from 84,153 Mcf in the first quarter of 2006, and an increaseof 2%, or $0.11,  in the average pricereceived for natural gas to $6.77 per Mcf in the first quarter of 2007 from$6.66 per Mcf in the first quarter of 2006. Gas products revenue increased$50,394, to $160,286 in the first quarter of 2007 from $109,892 in 

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the first quarter of 2006due primarily to an increase in production volume to 194,427 gallons from141,784 gallons.

Capital expenditures decreased $794,027, from$1,727,567 in the first quarter of 2006 to $933,540 in the first quarter of2007. The decrease in capital expenditures for the first quarter of 2007related primarily to a decrease in capital projects due to damages caused byHurricanes Rita and Katrina.

The Trust had undistributed net income of $2,092 inthe first quarter of 2007.

In the first quarter of 2007, there was a net depositof funds into the Special Cost Escrow account. The Trust’s share of the fundsdeposited was approximately $811,000. The deposit was primarily a result ofadditional future estimated abandonment costs and future capital expenditures.As of March 31, 2007, $7,648,195 remained in the Special Cost Escrowaccount. The Special Cost Escrow is set aside for estimated abandonment costsand future capital expenditures as provided for in the Conveyance. Foradditional information relating to the Special Cost Escrow, see “—Special CostEscrow” account below.

In the first quarter of2006, there was a net deposit of funds into the Special Cost Escrow account.The Trust’s share of the funds deposited was $876,000.

**Reserve for FutureTrust Expenses**

In accordance with theprovisions of the Trust Agreement, generally all Royalty income received by theTrust, net of Trust general and administrative expenses and any cash reservesestablished for the payment of contingent or future obligations of the Trust,are distributed currently to the Unit holders. In the first quarter of 1998,the Trust determined that the Trust’s cash reserve was sufficient at that timeto provide for future administrative expenses in connection with the winding upof the Trust. The Trust determined that a cash reserve equal to approximatelythree times the average expenses of the Trust during each of the past threeyears was sufficient at this time to provide for future administrative expensesin connection with the winding up of the Trust. During the first quarter of2007, the Trust increased its reserve by $254,027 for a reserve balance of$1,877,893 as of March 31, 2007. The reserve amount at March 31, 2006was $1,199,813.

**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**

At the end of October 2005,approximately half of Chevron oil-equivalent production in the Gulf of Mexicoremained shut in due to damages from hurricanes in the third quarter. The timeit will take to resume this production is uncertain, and some of the volumesmay not be sufficiently economic to restore. 

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As of March 31,2007, Eugene Island 339 gas sales had not resumed, but production is currentlyexpected to resume during the third quarter of 2007. The operator of thepipeline has advised that the hurricane-related damages on the pipeline wereextensive and repair work has been suspended indefinitely. However, theoperator is planning to connect the gas line from Eugene Island 339 to a thirdparty’s existing pipeline in order to resume production. The Working InterestOwner has also advised the Trust that the Working Interest Owner has completedthe project to compress and re-inject gas to the B-5 well, which allowsthe operator to increase oil production and to limit flaring of gas. EugeneIsland 339 oil production increased during the third quarter of 2006 andincreased further during the fourth quarter of 2006 and the first quarter 2007as the B-5 well gas injection project was completed. On Ship Shoal182/183, gas production and sales resumed in July 2006 and full productionresumed in the fourth quarter of 2006. On West Cameron 643, production was shutin from September 2005 following Hurricane Rita’s major damage to variousplatforms, but limited gas production resumed in late July 2006 before thewells loaded up and additional repairs were required.

**Three Months Ended March 31,2007 and 2006**

The following operational information has been basedon information provided to the Corporate Trustee by Chevron as the ManagingGeneral Partner of the Partnership and by the applicable Working InterestOwners. The Trustees have no control over these operations or internal controlsrelating to this information.

*Volumes and dollar amounts discussed belowrepresent amounts recorded by the Working Interest Owners unless otherwisespecified.*

Ship Shoal 182/183 crude oil revenues increased from$4,596,633 in the first quarter of 2006 to $4,939,120 in the first quarter of2007, partially due to an increase in net crude oil production from 76,556barrels in the first quarter of 2006, which included an adjustment of 6,447barrels relating to the fourth quarter of 2005, to 76,761 barrels in the firstquarter of 2007, which included an adjustment of 11,674 barrels relating to2006 production. The average crude oil price increased from $60.04 per barrelin the first quarter of 2006 to $64.34 per barrel for the same period in 2007.Gas revenues increased from $0 in the first quarter of 2006 to $2,233,646 inthe first quarter of 2007 due to wells coming back online after damages causedby Hurricanes Rita and Katrina. Gas production increased from 0 Mcf in thefirst quarter of 2006 to 320,577 Mcf in the first quarter of 2007. Capitalexpenditures decreased from $718,062 in the first quarter of 2006 to $470,908in the first quarter of 2007 primarily due to less repair and upgrade work onthe platforms associated with damages caused by Hurricanes Rita and Katrina.Operating expenses increased from $539,059 in the first quarter of 2006 to$990,592 for the same period in 2007 due to wells coming back online.

Eugene Island 339 net crude oil revenues increasedfrom $941,690 in the first quarter of 2006 to $4,616,444 for the same period in2007 due to an increase in volumes to 80,811 barrels from 21,299 barrels in thefirst quarter of 2006. In addition, the average crude oil price increased from$44.21 per barrel in the first quarter of 2006 to $57.13 per barrel in thefirst quarter of 2007. Gas revenues decreased from $547,819 in the firstquarter 2006 to $0 in the first quarter of 2007.There was  a decrease in natural gas volumes from 83,101Mcf in the first quarter of 2006 to 0 Mcf in the first quarter of 2007. Theoperator is building a new sales point which is expected to be completed duringthe second quarter 2007. Capital expenditures decreased from $962,783 in thefirst quarter of 2006 to $55,106 in the first quarter of 2007 due to less 

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repair and upgrade work onthe platforms associated with damages caused by Hurricanes Rita and Katrina.Operating expenses increased from $206,737 in the first quarter of 2006 to$590,601 in the first quarter of 2007.

West Cameron 643 gas revenues increased from $0 in thefirst quarter of 2006 to $219,217 in the first quarter of 2007. This is due toan increase in gas volumes from 0 Mcf in the first quarter of 2006 to 42,094Mcf for the same period in 2007 as a result of production from wells coming backonline. Operating expenses increased from $169,016 in the first quarter of 2006to $222,435 for the same period in 2007, and capital expenditures decreasedfrom $46,155 in the first quarter of 2006 to $0 for the same period in 2007.

East Cameron 371 crude oilrevenues were $0 in the first quarter of 2006 and in the first quarter of 2007as a result of no production during both periods. Oil sales are expected toresume during the second quarter 2007. Gas revenues increased from $0 in thefirst quarter of 2006 to $14,724 in the first quarter of 2007. This is due toan increase in gas volumes from 0 Mcf in the first quarter of 2006 to 2,298 Mcffor the same period in 2007. Operating expenses increased from $4,033 in thefirst quarter of 2006 to $12,306 in the first quarter of 2007.

**Future Net Revenuesand Termination of the Trust**

Based on a reserve studyprovided to the Trust by DeGolyer and MacNaughton, independent petroleumengineers, as of October 31, 2006 future net revenues attributable to theTrust’s royalty interests were estimated at $38.3 million. Estimates ofproved oil and gas reserves attributable to the Partnership’s royalty interestare based on existing economic and operating conditions in effect at October 31,2006 in order to correspond with distributions to the Trust. Such reserve studyalso indicates that approximately 72% of the future net revenues from theRoyalty Properties are expected to be received by the Trust during the nextthree years. In addition, because the Trust will terminate in the eventestimated future net revenues fall below $2.0 million, it would bepossible for the Trust to terminate even though some or all of the RoyaltyProperties continued to have remaining productive lives. Upon termination ofthe Trust, the Trustees will sell for cash all of the assets held in the Trustestate and make a final distribution to Unit holders of any funds remainingafter all Trust liabilities have been satisfied. The estimates of future netrevenues discussed above are subject to large variances from year to year andshould not be construed as exact. There are numerous uncertainties present inestimating future net revenues for the Royalty Properties. The estimate mayvary depending on changes in market prices for crude oil and natural gas, therecoverable reserves, annual production and costs assumed by DeGolyer andMacNaughton. In addition, future economic and operating conditions as well asresults of future drilling plans may cause significant changes in suchestimate. The discussion set forth above is qualified in its entirety byreference to the Trust’s Annual Report on Form 10-K for the yearended December 31, 2006. The Trust’s Form 10-K is available atthe website of the Securities and Exchange Commission (“SEC”) at *www.sec.gov* or upon request from the Corporate Trustee.

**Special Cost EscrowAccount**

The Conveyance provides for reserving funds forestimated future “Special Costs” of plugging and abandoning wells, dismantlingplatforms and other costs of abandoning the Royalty Properties, as well as forthe estimated amount of future drilling projects and other capital expenditureson the Royalty Properties. As provided in the Conveyance, the amount of fundsto be reserved is determined based on 

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factors includingestimates of aggregate future production costs, aggregate future Special Costs,aggregate future net revenues and actual current net proceeds. Deposits intothis account reduce current distributions and are placed in an escrow accountand invested in short-term certificates of deposit. Such account is hereinreferred to 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 proceeds to pay such costs. Special Costs that have been paid are no longerincluded in the Special Cost Escrow calculation. Deposits to the Special CostEscrow account will generally be made when the balance in the Special CostEscrow account is less than 125% of estimated future Special Costs and there isa Net Revenues Shortfall (a calculation of the excess of estimated future costsover estimated future net revenues pursuant to a formula contained in theConveyance). When there is not a Net Revenues Shortfall, amounts in the SpecialCost Escrow account will generally be released, to the extent that SpecialCosts have been incurred. Amounts in the Special Cost Escrow account will alsobe released when the balance in such account exceeds 125% of estimated futureSpecial Costs. In the first quarter of 2007, there was a net deposit of fundsto the Special Cost Escrow account of $809,215. The deposit was primarily aresult of additional future estimated abandonment costs and future capitalexpenditures.

As of March 31, 2007, $7,648,195 remained in theSpecial Cost Escrow account.

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

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**Overview ofProduction, Prices and Royalty Income**

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

| ** **                                                   | ** ** | **Royalty Properties**      | ** ** |
|--------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                   | ** ** | **Three Months Ended** | ** ** |
| ** **                                                   | ** ** | **March 31,(1)**            | ** ** |
| ** **                                                   | ** ** | **2007**                         | ** ** | **2006** | ** ** |
| Crude oil and  condensate (bbls)                             |       | 160,005                          |       | 99,608 |   |
| Natural gas and  gas products (Mcfe)                         |       | 399,037                          |       | 104,408 |   |
| Crude oil and  condensate average price, per bbl             |       | $                                | 60.62      |   | $ | 56.60 |   |
| Natural gas  average price, per Mcf (excluding gas products) |       | $                                | 6.77       |   | $ | 6.66 |   |
| Crude oil and  condensate revenues                           |       | $                                | 9,699,483  |   | $ | 5,637,176 |   |
| Natural gas and  gas products revenues                       |       | 2,672,774                        |       | 670,025 |   |
| Production  expenses                                         |       | (2,295,365                       | )          | (1,208,736 | ) |
| Capital  expenditures                                        |       | (933,540                         | )          | (1,727,567 | ) |
| Undistributed net  income(2)                                 |       | (2,092                           | )          | — |   |
| Refund of  (provision for) Special Cost Escrow               |       | (3,073,916                       | )          | (3,370,898 | ) |
| **Net  Proceeds**                                            |       | 6,067,344                        |       | — |   |
| Royalty interest                                             |       | x25                              | %          | x25 | % |
| Partnership share                                            |       | 1,516,836                        |       | — |   |
| Trust interest                                               |       | x99.99                           | %          | x99.99 | % |
| Trust share of Royalty  income                               |       | $                                | 1,516,684  |   | $ | — |   |

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(1)          Amounts represent actualproduction for the three month period ended January of each year,respectively.

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

**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 31,2006. 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.

*Evaluationof disclosure controls and procedures.**  *The Corporate Trustee maintainsdisclosure controls and procedures designed to ensure that information requiredto be disclosed by the Trust in the reports that it files or submits under theSecurities Exchange Act of 1934, as amended, is recorded, 

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processed, summarized andreported within the time periods specified in the SEC’s rules andregulations. Disclosure controls and procedures include controls and proceduresdesigned to ensure that information required to be disclosed by the Trust isaccumulated and communicated by Chevron, as the managing general partner of thePartnership, and the Working Interest Owners to The Bank of New York TrustCompany, N.A., as Corporate Trustee of the Trust, and its employees whoparticipate in the preparation of the Trust’s periodic reports as appropriateto allow timely decisions regarding required disclosure.

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

Due to the contractual arrangements of (i) theTrust Agreement, (ii) the Partnership Agreement and (iii) the rightsof the Partnership under the Conveyance regarding information furnished by theWorking Interest Owners, the Trustees rely on (A) information provided bythe Working Interest Owners, including historical operating data, plans forfuture operating and capital expenditures, reserve information and informationrelating to projected production, (B) information from the managinggeneral partner of the Partnership, including information that is collectedfrom the Working Interest Owners, and (C) conclusions and reports regarding reserves bythe Trust’s independent reserve engineers. See Item 1A. Risk Factors “—TheTrustees and the Trust Unit holders have no control over the operation ordevelopment of the Royalty Properties and have litte influence over operationor development” in the Trust’s Annual Report on Form 10-K for theyear ended December 31, 2006, and “Note 5—Negative Adjustments” of thefinancial statements and “Management’s Discussion and Analysis of FinancialCondition and Results of Operating” relating to operating information on EastCameron 371 included in the Annual Report on Form 10-K for the yearended December 31, 2006 for a description of certain risks relating tothese arrangements and reliance and applicable adjustments to operatinginformation when reported by the Working Interest Owners to the CorporateTrustee and recorded in the Trust’s results of operation.

*Changes in InternalControl Over Financial Reporting.**  *During the three months ended March 31,2007, there has been no change in the Corporate Trustee’s internal control overfinancial reporting that has materially affected, or is reasonably likely tomaterially affect, the Corporate Trustee’s internal control over financialreporting relating to the Trust. The Corporate Trustee notes for purposes ofclarification that it has no authority over, and makes no statement concerning,the internal control over financial reporting of the Working Interest Owners orthe managing general partner of the Partnership.

**PART II—OTHERINFORMATION**

**Item 1A.**                RiskFactors.

There have not been any material changes from riskfactors previously disclosed in the Trust’s response to Item 1A of Part 1of its Annual Report on Form 10-K for the year ended December 31,2006.

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**PART II—OTHERINFORMATION**

**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  as of January 1, 1983 (Exhibit 4(e) to Form 10-K  for the year ended December 31, 1992 of TEL 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:                |   | The Bank of New York  Trust Company, N. A. Corporate Trustee |
|       | By:                | ** ** | /s/  MIKE ULRICH |
| ** ** | ** **         | ** ** | **Mike  Ulrich*Vice President*** |

 

Date: May 15, 2007

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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