**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

## **FORM 10-K**

## ** **

**ý****                                ****ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934**

 

**FOR THE FISCAL YEAR ENDEDDECEMBER 31, 2005**

 

**OR**

 

**o****                                ****TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934**

 

**FOR THE TRANSITION****PERIOD FROM                           TO                           **

** **

**Commissionfile number: 1-11748**

 

## **Eastern American Natural GasTrust**

(Exact name ofregistrant as specified in its Charter)

 

| **Delaware**                                                                                             |   | **36-7034603**                        |
|----------------------------------------------------------------------------------------------------------|--------|---------------------------------------|
| (State or other  Jurisdiction of  Incorporation or Organization)                                         |   | (I.R.S. Employer  Identification No.) |
|                                                                                                     |   |                                  |
| **JPMorgan  Chase Bank, Trustee  Institutional Trust Services  700 Lavaca, 2nd Floor  Austin, TX 78701** |
| (Address of principal  executive office) (Zip Code)                                                      |

 

**(800)852-1422**

(Registrant’stelephone number, including area code)

 

Securitiesregistered pursuant to Section 12(b) of the Act:

 

| **Title of Each Class**       | ** ** | **Name of Each Exchange  On Which Registered** |
|-------------------------------|------------|------------------------------------------------|
|                          |       |                                           |
| Units of  Beneficial Interest |       | New York Stock  Exchange                       |

 

Securitiesregistered pursuant to Section 12(g) of the Act:

**None**

 

Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined in Rule 405 in theSecurities Act.Yes o No ý

 

Indicate by check mark ifthe registrant is not required to file reports pursuant to Section 13 orSection 15(d) of the Exchange Act. Yes oNo ý

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to filesuch reports) and (2) has been subject to such filing requirements for the past90 days: Yes ý No o

 

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained herein, and will not be contained, to the best of the registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

 

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer. (See definition of “accelerated filer” and “largeaccelerated filer” in Rule 12b-2 of the Exchange Act).

 

Large accelerated filer  o            Acceleratedfiler  ý           Non-acceleratedfiler o

 

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

 

As of June 30, 2005,5,900,000 Units of Beneficial Interest in Eastern American Natural Gas Trustwere issued, outstanding and held by non-affiliates of the registrant (the “OutstandingUnits”). Of the Outstanding Units, 119,900 Units of Beneficial Interest (the “WithdrawnUnits”) have been withdrawn from trading by voluntary action of Holders and maynot be traded unless such Holders comply with certain requirements provided inthe related Trust Agreement.

 

The aggregate marketvalue of the Outstanding Units minus the Withdrawn Units at the closing salesprice on June 30, 2005 of $28.00 was approximately $162 million.

 

Documents Incorporated ByReference: **None**

 

 

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**TABLEOF CONTENTS**

 
|       |   |                                                                                                                    | **PART I** |   |
|------------|--------|-------------------------------------------------------------------------------------------------------------------------|------------|--------|
|       |   |                                                                                                                    |       |   |
| Item 1.    |   | Business                                                                                                                | 1          |
|       |   | Description of the Trust                                                                                                | 1          |
|       |   | The Net Profits Interests                                                                                               | 3          |
|       |   | The  Underlying Properties                                                                                              | 6          |
|       |   | Competition and Markets                                                                                                 | 8          |
|       |   | Regulation of Natural Gas                                                                                               | 8          |
|       |   | Health, Safety and  Environmental Regulation                                                                            | 9          |
|       |   | Description of Trust Units  and Depositary Units                                                                        | 10         |
|       |   | Federal Income Tax Matters                                                                                              | 12         |
|       |   | State Tax  Considerations                                                                                               | 18         |
|       |   | Available Information                                                                                                   | 18         |
| Item 1A.   |   | Risk Factors                                                                                                            | 18         |
| Item 1B.   |   | Unresolved  Staff Comments                                                                                              | 22         |
| Item 2.    |   | Properties                                                                                                              | 22         |
| Item 3.    |   | Legal Proceedings                                                                                                       | 22         |
| Item 4.    |   | Submission  of Matters to a Vote of Unitholders                                                                         | 22         |
|       |   |                                                                                                                    |       |
|       |   | **PART II**                                                                                                             | 22         |
|       |   |                                                                                                                    |       |
| Item 5.    |   | Market for  the Registrant’s Common Equity, Related Unitholders Matters and Issuer  Purchases of Equity Securities | 22         |
| Item 6.    |   | Selected  Financial Data                                                                                                | 23         |
| Item 7.    |   | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                             | 23         |
| Item 7A.   |   | Quantitative  and Qualitative Disclosure About Market Risk                                                              | 27         |
| Item 8.    |   | Financial  Statements and Supplementary Data                                                                            | 27         |
| Item 9.    |   | Changes in  and Disagreements with Accountants on Accounting and Financial Disclosure                                   | 28         |
| Item 9A.   |   | Controls and  Procedures                                                                                                | 28         |
| Item 9B.   |   | Other Information                                                                                                       | 29         |
|       |   |                                                                                                                    |       |
|       |   | **PART  III**                                                                                                           | 29         |
|       |   |                                                                                                                    |       |
| Item 10.   |   | Directors  and Executive Officers of the Registrant                                                                     | 29         |
| Item 11.   |   | Executive  Compensation                                                                                                 | 30         |
| Item 12.   |   | Security  Ownership of Certain Beneficial Owners and Management                                                         | 30         |
| Item 13.   |   | Certain  Relationships and Related Transactions                                                                         | 30         |
| Item 14.   |   | Principal  Accounting Fees and Services                                                                                 | 30         |
|       |   |                                                                                                                    |       |
|       |   | **PART IV**                                                                                                             | 31         |
|       |   |                                                                                                                    |       |
| Item 15.   |   | Exhibits,  Financial Statement Schedules                                                                                | 31         |
|       |   |                                                                                                                    |       |
| SIGNATURES |   | 32                                                                                                                      |

 

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**PART I**

 

**Item 1.    *Business***

 

**CautionaryStatement**

** **

The Trustee (as definedbelow), its officers or its agents on behalf of the Trustee may, from time totime, make forward-looking statements (other than statements of historicalfact). In addition, this Report on Form 10-K may contain forward-lookingstatements. When used herein, the words “anticipates,” “expects,” “believes,” “intends”or “projects” and similar expressions are intended to identify forward-lookingstatements. To the extent that any forward-looking statements are made, theTrustee is unable to predict future changes in gas prices, gas productionlevels, economic activity, legislation and regulation, and certain changes inexpenses of the Trust (as defined below). In addition, the Trust’s futureresults of operations and other forward looking statements contained in thisItem 1, Item 1A and elsewhere in this report involve a number of risks anduncertainties. As a result of variations in such factors, actual results maydiffer materially from any forward-looking statements. Some of these factorsare described below. The Trustee disclaims any obligations to update forwardlooking statements and all such forward-looking statements in this document areexpressly qualified in their entirety by the cautionary statements in thisparagraph. Further, forward-looking statements made herein regarding the Trustand its operation in this Form 10-K generally assume that the pending exchangeoffer being made by Ensource Energy Income Fund LP as described below will notresult in Ensource acquiring control of the Trust. Ensource has stated that ifit acquires control of the Trust, it intends to attempt to cause the Trust toengage in a merger that would result in significant changes to the Trust.

 

**Definitions**

 

As used herein, thefollowing terms have the meanings indicated: “Mcf” means thousand cubic feet ofgas, “MMcf” means million cubic feet of gas, “Bbl” means barrel (approximately42 U.S. gallons), and “MBbl” means thousand barrels, “Btu” means Britishthermal units and “MMBtu” or “Dth” means million British thermal units.

 

The followingdescriptions of the Eastern American Natural Gas Trust (the “Trust”), theDepositary Units, the Net Profits Interests, the Underlying Properties and thecalculation of amounts payable to the Trust, are subject to and qualified intheir entirety by the more detailed provisions of the Trust Agreement, theDepositary Agreement, the Conveyances and the Gas Purchase Contract (each asdefined below), all of which are incorporated by reference as exhibits to thisForm 10-K and available upon request from JPMorgan Chase Bank, N.A. at theaddress set forth herein. The information contained herein relating to theoperations of the Underlying Properties, as well as information upon which thereserve figures and financial information contained herein were derived, wasfurnished to the Trustee by Eastern American Energy Corporation (“EasternAmerican”).

 

**DESCRIPTIONOF THE TRUST**

 

The Trust was formedunder the Delaware Business Trust Act pursuant to a Trust Agreement (the “TrustAgreement”) among Eastern American, as grantor, Bank of Montreal Trust Company,as trustee, and Wilmington Trust Company, as Delaware Trustee (the “DelawareTrustee”). Effective May 8, 2000, The Bank of New York acquired the corporatetrust business of the Bank of Montreal Trust Company / Harris Trust, andconsequently, The Bank of New York served as trustee of the Trust. On November20, 2004, the holders of a majority of the Trust Units voting at a specialmeeting approved the resignation of The Bank of New York as trustee anddepository of the Trust and the appointment of JPMorgan Chase Bank, N.A. assuccessor trustee of the Trust. The appointment of JPMorgan Chase Bank, N.A. assuccessor trustee became effective as of January 1, 2005. Consequently,references herein to the “Trustee” mean JPMorgan Chase Bank, N.A. as successortrustee, on and after January 1, 2005. References to the “Trustee” at any timeprior to January 1, 2005 mean The Bank of New York as trustee. EffectiveJanuary 1, 2005, the transfer agent for the Trust is Bondholder Communications.

 

The Trust was formed toacquire and hold net profits interests (the “Net Profits Interests”) createdfrom the working interests owned by Eastern American in 650 producing gas wellsand 65 proved development well locations located in West Virginia andPennsylvania (the “Underlying Properties”). A portion of the production fromthe wells burdened by the Net Profits Interests was intended to be eligible forcredits (“Section 29 Credits”) under the Internal Revenue Code of 1986 forproduction of gas from Devonian shale or tight formations. The Net ProfitsInterests to be acquired consisted of a royalty interest in 322 wells and aterm interest in the remaining wells and development well

 

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locations. Eastern American was obligated to drill and complete, at itsexpense, 65 development wells (the “Development Wells”) on the development welllocations conveyed to the Trust. Eastern American has fulfilled its obligationwith respect to the drilling of the Development Wells (see Note 1 of FinancialStatements attached hereto). After May 15, 2012 and prior to or on May 15, 2013(the “Liquidation Date”), the Trustee is required to sell the remaining royaltyinterests and liquidate the Trust.

 

On March 15, 1993,5,900,000 Depositary Units were issued in a public offering at an initialpublic offering price of $20.50 per Depositary Unit. Each Depositary Unitconsists of beneficial ownership of one unit of beneficial interest (“TrustUnit”) in the Trust and a $20 face amount beneficial ownership interest in a$1,000 face amount zero coupon United States Treasury obligation (“TreasuryObligation”) maturing on May 15, 2013. Holders of Depositary Units (“Unitholders”)may withdraw the Treasury Obligations associated with the Trust Units (see “Descriptionof Trust Units and Depositary Units”). Of the net proceeds from such offering,$27,787,820 was used to purchase $118,000,000 in face amount of TreasuryObligations and $93,162,180 was retained by Eastern American in considerationfor the conveyance of the Net Profits Interests to the Trust. The Trustacquired the Net Profits Interests effective as of January 1, 1993.

 

The Net Profits Interestsare passive in nature, and neither the Trustee nor the Delaware Trustee hasmanagement control or authority over, nor any responsibility relating to, theoperation of the Underlying Properties (defined above) subject to the NetProfits Interests. The Trust Agreement provides, among other things, that: theTrust shall not engage in any business or commercial activity or acquire anyasset other than the Net Profits Interests initially conveyed to the Trust; theTrustee may establish a reserve for payment of any liability which iscontingent, uncertain in amount or that is not currently due and payable; theTrustee is authorized to borrow funds required to pay liabilities of the Trust,provided that such borrowings are repaid in full prior to further distributionsto Unitholders and other holders of Trust Units (together, “Trust Unitholders”);and the Trustee will make quarterly cash distributions to Trust Unitholdersfrom funds of the Trust.

 

The Trust isresponsible for paying the Trustee’s fees and all legal, accounting,engineering and stock exchange fees, printing costs and other administrativeexpenses incurred by or at the direction of the Trustee. The total fees paid tothe Trustee for 2005 were $108,000. The total of all Trustee fees and Trustadministrative expenses for 2005 was $1,474,570. Such costs could fluctuate inthe future depending primarily on the expenses the Trust incurs forprofessional services, particularly legal, accounting and engineering services.In addition to such expenses, in 2005, the Trust paid Eastern American anoverhead reimbursement of $317,324. The overhead reimbursement was establishedat the inception of the Trust, increases by 3.5% per year, and is payablequarterly.

 

On December 8, 2004, theTrust announced approval by the Trust Unitholders of a proposal to electJPMorgan Chase to serve as successor trustee of the Trust upon the effectivedate of the resignation of The Bank of New York as trustee of and depositary forthe Trust and to amend the Trust Agreement to change the compensation of theTrustee. The resignation of The Bank of New York took effect on January 1, 2005.As successor trustee, JPMorgan Chase receives annual compensation of $108,000.

 

As previously publicly announced, Ensource EnergyIncome Fund LP, a recently formed Delaware limited partnership not affiliatedwith the Trust (“Ensource”), has commenced an unsolicited exchange offerpursuant to which Ensource is attempting to acquire control of, and ultimatelythe entire interest in, the Trust. The Trust has filed a Schedule 14D-9,including Amendment No. 1 thereto (the “Schedule 14D-9”) with the Securitiesand Exchange Commission, and has mailed copies of the Schedule 14D-9 toUnitholders of record. In the Schedule 14D-9, the Trust recommends thatUnitholders reject the Ensource offer. The reasons for the Trust’srecommendation, as well as a copy of the opinion of an independent financialadvisor retained by the Trust in connection with the Ensource offer and otherimportant information, are set forth in the Schedule 14D-9. Unitholders shouldreview the Schedule 14D-9 carefully before making any decision to tender theirunits to Ensource. Copies of the Schedule 14D-9 may be obtained by contactingMacKenzie Partners, Inc. toll-free at 1-800-332-2885 or over the Internet fromthe SEC’s web site at http://www.sec.gov.

 

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###### **THE NET PROFITSINTERESTS**

###### ** **

**The Conveyances**

 

The Net Profits Interests(“NPI”) were created from the Underlying Properties and conveyed to the Trustpursuant to two Conveyances - one conveying a royalty interest in specifiedwells (the “Royalty NPI Conveyance”) and the other conveying the a terminterest in specified wells (the “Term NPI Conveyance”, and together with theRoyalty NPI Conveyance, the “Conveyances”). Forms of the Conveyances have beenincorporated by reference as exhibits to this report.

 

The Underlying Propertiesare subject to and burdened by the Net Profits Interests. The interests ofEastern American comprising the Underlying Properties represent, on average, aworking interest of approximately 90% and a net revenue interest ofapproximately 76%. The Conveyances provide that the Trust is only entitled togas produced from the specific wells identified in the Conveyances and is notentitled to any gas produced from adjacent wells (including adjacent wellssubject to the same lease or farmout agreement as the wells subject to the NetProfits Interests). Gas produced from the Underlying Properties which isattributable to the Net Profits Interests is purchased from the Trust byEastern Marketing Corporation, a wholly-owned subsidiary of Eastern American (“EasternMarketing”) pursuant to a gas purchase contract (the “Gas Purchase Contract”).The volumes attributable to the Net Profits Interests and the purchase pricefor such gas is calculated for each calendar quarter, and payment for such gasis made to the Trust not later than the 10th day of the third calendar monthfollowing the end of each calendar quarter.

 

The Royalty NPI is notlimited in term or amount. Under the Trust Agreement, the Trustee is directedto sell all remaining Royalty NPI after May 15, 2012 and prior to May 15, 2013,and net proceeds from selling such Royalty NPI will be distributed toUnitholders on the first quarterly payment date following the receipt of suchproceeds by the Trust. The Term NPI will expire on the earlier of May 15, 2013or such time as 41,683 MMcf of gas has been produced which is attributable toEastern American’s net revenue interests in the properties burdened by the TermNPI. As of December 31, 2005, 21,814 MMcf of such gas had been produced. TheTrust is expected to terminate in 2013. See “Description of Trust Units andDepository Units – Liquidation of the Trust”.

 

Eastern American can sellthe Underlying Properties, subject to and burdened by the Net ProfitsInterests, without the consent of the Trustee or the Unitholders. In limitedcircumstances, Eastern American also can transfer the Underlying Properties andrequire the Trust to release the NPI burdening that property, without theconsent of the Trustee or Unitholders, subject to payment to the Trust of thefair value of the interest released. In addition, any abandonment of a well includedin the Underlying Properties or the Development Wells will extinguish thatportion of the Net Profits Interests that relate to such well. See “Sale andAbandonment of Underlying Properties; Sale of Royalty NPI.”

 

**Calculation of Net Proceeds**

 

The definitions,formulas, accounting procedures and other terms governing the computation ofNet Proceeds are detailed and extensive, and reference is made to both theRoyalty NPI Conveyance and the Term NPI Conveyance for a more detaileddiscussion of the computation thereof.

 

The Conveyances and theGas Purchase Contract entitle the Trust to receive an amount of cash for eachcalendar quarter equal to the Net Proceeds for such quarter. “Net Proceeds” forany calendar quarter generally means an amount of cash equal to (a) 90% of avolume of gas equal to (i) the volume of gas produced during such quarterattributable to the Underlying Properties less (ii) a volume of gas equal toChargeable Costs, as defined below, for such quarter, multiplied by (b) theapplicable price for such quarter under the Gas Purchase Contract. If, for anyreason, the Gas Purchase Contract terminates prior to the Liquidation Date, “NetProceeds” will mean an amount of cash equal to (a) 90% of a volume of gas equalto (i) the volume of gas produced during such quarter attributable to theUnderlying Properties less (ii) a volume of gas equal to Chargeable Costs forsuch quarter, multiplied by (b) the applicable price for such quarterdetermined in accordance with the Conveyances. Pursuant to the Conveyances, theTrust is not entitled to receive any natural gas liquids produced from theUnderlying Properties or any proceeds relating thereto.

 

“Chargeable Costs” isthat volume of gas which equates in value, determined by reference to therelevant sales price under the Gas Purchase Contract or the Conveyances, asapplicable, to the sum of the “Operating Cost Charge”, “Capital Costs” and “Taxes”(as defined in the Conveyances). The Operating Cost Charge for 2005 was$534,348, for 2004 was $519,228 and for 2003 was $510,032. As provided in theConveyances, the Operating Cost Charge will

 

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increase based on the lesser of (A) five percent (5%) or (B) apercentage, not less than zero percent (0%), equal to the percentage increase,if any, in the average weekly earnings of Crude Petroleum and Gas ProductionWorkers for the last calendar year, as shown by the index of average weeklyearnings of Crude Petroleum and Gas Production Workers, as published by theUnited States Department of Labor, Bureau of Labor Statistics, based onDecember-to-December comparison.

 

During 2003, the UnitedStates Department of Labor, Bureau of Labor Statistics converted all of itsindustry-based statistics to a different reporting system that was developed incooperation with the United States’ North American Free Trade AgreementPartners, Canada and Mexico, in an effort to standardize and modernizereporting codes. As a result of this conversion, the Crude Petroleum and GasProduction Workers index is no longer available for use in the annualcalculation of overhead adjustment called for in the various Council ofPetroleum Accountants Societies, or COPAS, model forms after March 2003.

 

Research by COPAS covering a ten year period indicatedthat by blending the Oil and Gas Extraction Index with the Professional andTechnical Services Index, the results approximate the data from the old CrudePetroleum and Natural Gas Workers Index. Accordingly, COPAS has calculated thepercentage change in the simple average of the Oil and Extraction Index and theProfessional and Technical Services Index, commencing in April 2004. This“Overhead Adjustment Index” has been provided as a guidance to the industry asa replacement index for use in calculating the overhead adjustment. Theadjustment for the effective time period is 3.5%. Since the ConveyanceDocuments do not specifically provide for a replacement index if the CrudePetroleum and Gas Production Workers Index was no longer published, EasternAmerican believes, and advised the Trustee, that the “Overhead AdjustmentIndex” as calculated by COPAS is a reasonable index to utilize since theindustry is generally adopting the same as a replacement. Eastern American,with the concurrence of the Trustee, will utilize this “Overhead AdjustmentIndex” to adjust the “Operating Cost Charge” so long as such index is publishedby COPAS.

 

The Operating Cost Chargewill be reduced for each well that is sold (free of the Net Profits Interests)or plugged and abandoned. Capital Costs are defined as Eastern American’sworking interest share of capital costs for operations on the UnderlyingProperties having a useful life of at least three years, and excluding anycapital costs incurred in drilling the Development Wells. Taxes refer to advalorem taxes, production and severance taxes, and other taxes imposed onEastern American’s or the Trust’s interests in the Underlying Properties, orproduction therefrom.

 

Although the Trustbears the full economic burden of Chargeable Costs, it does so indirectly inthe calculation of Net Proceeds and the Trust is not directly liable for anyshare of the costs, risks, and liabilities associated with the ownership oroperation of the Underlying Properties. If the Trust ever receives payments inexcess of the Net Proceeds or other amounts it was not entitled to receive, theTrust will not be required to refund the money, but Eastern American mayrecover the amount of such overpayments from future distributions in accordancewith the Conveyances.

 

The Conveyances requireEastern American to maintain books, records, and accounts sufficient tocalculate the volumes of gas and the share of Net Proceeds payable to theTrust. Eastern American provides to the Trust quarterly and annual statementsof applicable production, revenues, and costs necessary for the Trust toprepare quarterly and annual financial statements with respect to the NetProfits Interests and the Underlying Properties. The financial statements ofthe Trust are audited annually at the Trust’s expense.

 

**Gas Purchase Contract**

 

Gas productionattributable to the Net Profits Interests is purchased from the Trust byEastern Marketing, a wholly owned subsidiary of Eastern American, pursuant tothe Gas Purchase Contract which effectively commenced as of January 1, 1993 andexpires upon the termination of the Trust.

 

Under the Gas PurchaseContract, Eastern Marketing purchases gas from the Trust at a variable pricefor each quarter equal to the Henry Hub Average Spot Price (as defined) perMMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment forBtu content. The Henry Hub Average Spot Price is defined as the price per MMBtudetermined for any calendar quarter equal to the price obtained with respect toeach of the three months in such quarter, in the manner specified below, andthen taking the average of the prices determined for each of such three months.The price determined for any month of such quarter is equal to the average of(i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts(as defined), as reported in *The Wall Street Journal,*forsuch contracts which expired in each of the five months prior to such month,(ii) the final settlement price per MMBtu for Henry Hub Gas Futures

 

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Contracts, as reported in *The Wall Street Journal,*forsuch contracts which expire during such month and (iii) the closing settlementprices per MMBtu of Henry Hub Gas Futures Contracts determined as of thecontract settlement date for such month, as reported in *The WallStreet Journal,*for such contracts which expire in each of the sixmonths following such month. A Henry Hub Gas Futures Contract is defined as agas futures contract for gas to be delivered to the Henry Hub, which is tradedon the New York Mercantile Exchange.

 

The purchase pricepaid to the Trust pursuant to the Gas Purchase Contract is a wellhead price andtitle to the gas purchased pursuant to the Gas Purchase Contract passes toEastern Marketing at the point of delivery. Payments to the Trust for gaspurchased pursuant to the Gas Purchase Contract are made by Eastern Marketingon or before the tenth day of the third calendar month following the end ofeach calendar quarter.

 

The Trust Agreementprovides that the Trustee may not agree to any amendment to the Gas PurchaseContract which would materially and adversely affect the revenues to the Trustwithout the approval of the holders of a majority of the outstanding TrustUnits. The Trust Agreement also provides that the Gas Purchase Contract may notbe terminated by the Trust without the approval of the holders of a majority ofthe outstanding Trust Units. The Gas Purchase Contract and the Trust Agreementhave been filed as exhibits to this Form 10-K. The foregoing summary of theprincipal provisions of the Gas Purchase Contract, and certain provisions ofthe Trust Agreement, is qualified in its entirety by reference to the terms ofsuch agreements as set forth in such exhibits.

 

Eastern Marketing’srights and obligations under the Gas Purchase Contract are assignable undercircumstances where the assignee unconditionally assumes Eastern Marketing’sobligations under the Gas Purchase Contract only if such assignee (or assignee’sparent corporation if such parent guarantees the assignee’s obligations) has arating assigned to its unsecured long-term debt by Moody’s Investor Service ofat least Baa+ and by Standard & Poor’s Corporation of at least BBB-. Undersuch circumstances, Eastern Marketing and Eastern American would be releasedfrom their obligations under the Gas Purchase Contract.

 

**Performance Support for GasPurchase Contract**

 

Gas productionattributable to the Net Profits Interests will be purchased by EasternMarketing pursuant to the Gas Purchase Contract, which expires upon theLiquidation Date of the Trust. Eastern American has agreed to make paymentunder a standby performance agreement to the extent such payments are not madeby Eastern Marketing under the Gas Purchase Contract.

 

**Distributions and IncomeComputations**

 

The Trustee determinesfor each quarter the amount of cash available for distribution to holders ofDepositary Units and the Trust Units evidenced thereby. Such amount (the “QuarterlyDistribution Amount”) is equal to the excess, if any, of (i) the cash that theTrust receives on or before the tenth day of the third month after the end ofeach calendar quarter ending before the Trust is dissolved and that isattributable to production from the Net Profits Interest held by the Trustduring that calendar quarter, plus, with certain exceptions, any other cashreceipts of the Trust during such quarter, over (ii) the liabilities ofthe Trust paid during such quarter, subject to adjustments for changes made bythe Trustee during such quarter in any cash reserves established for thepayment of contingent or future obligations of the Trust. QuarterlyDistribution Amounts for each of the quarters in 2005 were $0.50, $0.51, $0.64,and $0.67 respectively. Based on the payment procedures relating to the NetProfits Interests, cash received by the Trustee in a particular quarter fromthe Net Profits Interests reflects actual gas production for a portion of suchquarter and a production estimate for the remainder of such quarter, such estimateto be adjusted to actual production in the following quarter. The QuarterlyDistribution Amount for each quarter is payable to Unitholders of record on thelast day of the second month following the end of such calendar quarter or suchlater date as the Trustee determines is required to comply with legal or stockexchange requirements (“Quarterly Record Date”). It is expected that theTrustee will continue to be able to distribute cash on or before the 15th day(or the next succeeding business day following such day if such day is not abusiness day) of the third month following the end of each calendar quarter toeach person who was a Unitholder of record on the Quarterly Record Date,together with interest earned on such Quarterly Distribution Amount from thedate of receipt thereof by the Trustee to the payment date.

 

The net taxable income ofthe Trust for each calendar quarter is reported by the Trustee for tax purposesas belonging to the holders of record to whom the Quarterly Distribution Amountwas or will be distributed. Assuming that the Trust will be classified for taxpurposes as a “grantor trust,” the net taxable income will be realized by theholders for

 

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tax purposes in the calendar quarter received by the Trustee, ratherthan in the quarter distributed by the Trustee. Thus, a Unitholder’s taxableincome for a taxable year may differ from the cash the Unitholder receivesduring that year. In addition, taxable income of a holder will differ from theQuarterly Distribution Amount because the Treasury Obligations will be treatedas generating interest income for tax purposes. There may also be minorvariances because of the possibilities that a reserve will be established inone quarter that will not give rise to a tax deduction until a subsequentquarter, an expenditure paid for in one quarter will have to be amortized fortax purposes over several quarters, or for other reasons. See “Federal IncomeTax Matters.”

 

Each holder ofDepositary Units (including the underlying Trust Units) of record as of therecord date for the final quarter of the Trust’s existence in accordance withthe Trust Agreement will be entitled to receive a liquidating distributionequal to a pro rata portion of the net proceeds from the sale of the RoyaltyNPI (to the extent not previously distributed) and a pro rata portion of theproceeds from the matured Treasury Obligations.

 

**Sale and Abandonment ofUnderlying Properties; Sale of Royalty NPI**

 

Eastern Americanand any transferees have the right to abandon any well or working interestincluded in the Underlying Properties if, in its opinion, such well or propertyceases to produce or is not capable of producing in commercially payingquantities. To reduce or eliminate the potential conflict of interest betweenEastern American and the Trust in determining whether a well is capable ofproducing in paying quantities, Eastern American is required under theConveyances to make any such determination as would a reasonably prudentoperator in the Appalachian Basin if it were acting with respect to its ownproperties, disregarding (i) the existence of the Net Profits Interests as aburden on such property and (ii) the direct or indirect effect, financial orotherwise, on Eastern American or any of its affiliates that may result fromthe performance by Eastern Marketing of its obligations under the Gas PurchaseContract.

 

Eastern Americanhas the right, pursuant to the Conveyances, to sell all or any portion of theUnderlying Properties without restrictions; however, the purchaser of any ofthe Underlying Properties will acquire such Underlying Properties subject tothe Net Profits Interests relating thereto (except in certain circumstancesdescribed below where the Trust may be required to release the Net ProfitsInterests, subject to its receipt of the fair value thereof). Any suchpurchaser will be subject to the same standards of conduct with respect todevelopment, operation and abandonment of such Underlying Properties as set forthin the preceding paragraph.

 

Eastern Americanmay sell the Underlying Properties, subject to and burdened by the Net ProfitsInterests, without the consent of the Trust or the Unitholders. In addition,until January 1, 2010, Eastern American can require the Trust to release theNet Profits Interests associated with the sale of wells, regardless of numberof wells sold, provided that such releases cannot exceed an aggregate value tothe Trust of $500,000 during any 12 month period. Sales subsequent to January1, 2010 may be made without regard to dollar limitations. These releases willbe made only in connection with a sale by Eastern American of the UnderlyingProperties and are conditioned upon the Trust receiving an amount equal to thefair value to the Trust of such Net Profits Interests (taking into account theexistence of the Gas Purchase Contract with respect to the gas attributable tothe Net Profits Interests to be released). Any proceeds paid to the Trust aredistributable to Unitholders for the quarter in which they are received.

 

The Trustee is requiredto sell all of the Royalty NPI after May 15, 2012 and prior to the LiquidationDate. The proceeds of such sale, together with the matured face amount of theTreasury Obligations, will be distributed to Unitholders on or prior to theLiquidation Date. Under the Trust Agreement, Eastern American has a right offirst refusal to purchase any of the Royalty NPI at the fair value to theTrust, or if applicable the offered third-party price, prior to the LiquidationDate.

 

**THEUNDERLYING PROPERTIES**

 

**General**

 

The Underlying Propertiesare comprised of Eastern American’s working interests in certain propertieslocated in the Appalachian Basin states of West Virginia and Pennsylvania. Asof December 31, 2005, such properties consisted of 671 producing gas wells. Theworking interests of Eastern American comprising the Underlying Properties areheld under leases and farmout agreements with third parties. Such workinginterests are subject to landowner’s royalties (typically 12-1/2%) and may besubject to additional royalties or other obligations burdening the workinginterests. Such royalties do not bear lease operating expenses, but reduce therevenue interests attributable to the Underlying Properties.

 

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Eastern American’s interests comprising the Underlying Propertiesrepresent, on average, a working interest of approximately 90% and a netrevenue interest of approximately 76%. As of December 31, 2005, proveddeveloped reserves attributable to the Net Profits Interests (reflectingquantities of gas free of future costs and expenses based on estimated prices)were approximately 17,263 MMcf. (See “Reserves”).

 

The Appalachian Basin isa mature producing region with well known geologic characteristics.Substantially all of the wells comprising the Underlying Properties arerelatively shallow, ranging from 2,500 to 5,500 feet, and many are completed tomultiple producing zones. In general, the wells to which the UnderlyingProperties relate are proved producing properties with stable productionprofiles and generally long-lived production, often with total projectedeconomic lives in excess of 25 years. Once drilled and completed, ongoingoperating and maintenance requirements are low and only minimal, if any,capital expenditures are typically required.

 

The Underlying Propertiesinitially included 65 specified development well locations for the drilling ofthe Development Wells by Eastern American. Eastern American was obligated tobear the costs of drilling and completing the Development Wells. EasternAmerican has fulfilled its obligation with respect to the drilling of theDevelopment Wells. See Note 1 of Financial Statements attached hereto.

 

Eastern American acquiredits interests in the Underlying Properties under or through (i) oil and gasleases granted by the mineral owner directly to Eastern American, (ii)assignments of oil and gas leases by the lessee who originally obtained theleases from the mineral owner, (iii) farmout agreements that grant EasternAmerican the right to earn interests in the properties covered by suchagreements by drilling wells and (iv) the acquisitions of oil and gas interestsby Eastern American.

 

Production from the wellsto which the Underlying Properties relate is typically subject to (i) landownerroyalties and other burdens and obligations retained under oil and gas leases,(ii) overriding royalty interests and (iii) interests of other working interestowners in the wells. The royalty and overriding interests entitle the holdersthereof to a certain percentage of the oil and gas produced from the wells orthe proceeds therefrom and are generally delivered free of all expenses ofproduction but may be subject to post-production costs, such as production orgathering taxes, costs to treat the gas to render it marketable, and certaintransportation or gathering costs. Royalty interests are usually reserved bythe lessor under an oil and gas lease. Overriding royalty interests are carvedout of a lessee’s share of production under an oil and gas lease and aregenerally reserved by a predecessor in title or reserved under farmoutagreements.

 

A farmout agreement istypically an agreement under which a lessee under an oil and gas lease (the “Farmor”)grants to another party the right to drill wells on the tract covered by suchlease and to earn certain acreage for drilling such wells. In the AppalachianBasin, the Farmor generally receives a well location fee and reserves anoverriding royalty interest in the wells which typically ranges from 3.25% to6.25%. Farmout agreements typically provide that wells must be drilled andcompleted as a condition to a transfer by the Farmor of the interest in theunderlying lease.

 

**Reserves**

 

*Proved Reservesof Underlying Properties and Net Profits Interests.*Thefollowing table sets forth, as of December 31, 2005, certain estimatedproved reserves, estimated future net revenues and the discounted present valuethereof attributable to the Underlying Properties, the Royalty NPI and the TermNPI, in each case derived from a report of oil and gas reserves attributable tothe Trust as of December 31, 2005 prepared by Ryder Scott Company (the “ReserveReport”). Proved reserve quantities attributable to the Net Profits Interestsare calculated by subtracting an amount of gas sufficient, if sold at theprices used in preparing the reserve estimates, to pay the future estimatedcosts and expenses deducted in the calculation of Net Proceeds. Accordingly,the reserves attributable to the Net Profits Interests reflect quantities ofgas that are free of future costs or expenses if the price and cost assumptionsset forth in the Reserve Report occur. A decrease in the price assumption, oran increase in the cost assumption used in the Reserve Report would reduce theestimates of proved reserves, future net revenues and discounted future netrevenues, set forth herein and in the Reserve Report. The Term NPI excludesproduction beyond the earlier of May 15, 2013 or such time as 41,683 MMcf ofgas has been produced which is attributable to Eastern American’s net revenueinterests in the properties burdened by the Term NPI. The discounted presentvalue of estimated future net revenues was determined using a discount rate of10% in accordance with applicable requirements. A copy of the Reserve Report isincluded as Exhibit A hereto.

 

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| ** **                | ** ** | **Proved Gas Reserves** | ** ** | **Estimated**           | ** ** | **Discounted  Estimated** | ** ** |
|---------------------------|------------|-------------------------|------------|-------------------------|------------|---------------------------|------------|
| ** **                | ** ** | **Developed**           | ** ** | **(MMcf)  Undeveloped** | ** ** | **Total**                 | ** ** | **Future Net  Revenues(2)** | ** ** | **Future Net  Revenues(2)** | ** ** |
| ** **                | ** ** | ** **              | ** ** | ** **              | ** ** | ** **                | ** ** | **(Dollars  in thousands)** | ** ** |
|                      |       |                    |       |                    |       |                      |       |   |   |   |   |
| Underlying  Properties(1) |       |                    | 34,653     |                    | 0          |                      | 34,653     |   | $ | 382,226 |   | $ | 154,236 |   |
|                      |       |                    |       |                    |       |                      |       |   |   |   |   |   |
| Net Profits Interests:    |       |                    |       |                    |       |                      |       |   |   |   |   |   |
| Royalty NPI               |       |                    | 11,266     |                    | 0          |                      | 11,266     |   | $ | 141,923 |   | $ | 59,278 |   |
| Term NPI                  |       |                    | 5,997      |                    | 0          |                      | 5,997      |   | 75,540 |   | 54,992 |   |
|                      |       |                    |       |                    |       |                      |       |   |   |   |   |   |
| Total                     |       |                    | 17,263     |                    | 0          |                      | 17,263     |   | $ | 217,463 |   | $ | 114,270 |   |

 

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(1)          Reservevolumes and estimated future net revenues for Underlying Properties reflectvolumes and revenues distributable to Eastern American’s entire net revenueinterest with respect to the Underlying Properties.

 

(2)          Theeffects of depreciation, depletion and federal income tax have not been takeninto account in estimating future net revenues. Estimated future net revenuesand discounted estimated future net revenues are not intended, and should notbe interpreted, as representing the fair market value for the estimatedreserves.

 

The value of theDepositary Units and the Trust Units evidenced thereby are substantiallydependent upon the proved reserves and production levels attributable to theNet Profits Interests. There are many uncertainties inherent in estimatingquantities and values of proved reserves and in projecting future rates ofproduction and the timing of development expenditures, if any. The reserve dataset forth herein, although prepared by independent engineers in a mannercustomary in the industry, are estimates only, and actual quantities and valuesof gas are likely to differ from the estimated amounts set forth herein. Inaddition, the discounted present values shown herein were prepared usingguidelines established by the Securities and Exchange Commission (the “Commission”)and the Financial Accounting Standards Board for disclosure of reserves andshould not be considered representative of the market value of such reserves orthe Depositary Units or the Trust Units evidenced thereby. A market valuedetermination would include many additional factors.

 

**COMPETITIONAND MARKETS**

 

All of the productionattributable to the Net Profits Interest is sold to Eastern Marketing pursuantto the Gas Purchase Contract. See “The Net Profits Interests - Gas PurchaseContract.”

 

**REGULATIONOF NATURAL GAS**

 

The natural gas industryhas historically been highly regulated by state and federal authorities. In thepast, concerns about perceived pipeline monopolies and other factors causedCongress to impose economic regulation on both pipelines and producers. Federalagencies regulated tariffs and conditions of service offered by interstatepipelines, and set maximum prices on the wellhead price of natural gas soldinto interstate commerce. States, and even local governments, also regulatedretail sales of natural gas by local utilities. Government agencies also setproduction rates to avoid waste and imposed environmental and safetyregulations. At present, it appears that Federal regulation of wellhead naturalgas prices has ended. However, there can be no assurance that price controls orother similar economic regulations may not be reimposed in the future.

 

Drilling and productionof natural gas are heavily regulated in Pennsylvania and West Virginia, as inmost states. A well cannot be drilled without a permit, and operations must beconducted in compliance with environmental, safety and conservation laws andregulations. In contrast to many other states which have substantial oil andgas production activity, the spacing of shallow wells (such as the wellssubject to the Net Profits Interests) is not regulated by any state statute orregulatory agency in either West Virginia or Pennsylvania. Without spacingrequirements specified by state statute or regulation, drainage of reservesfrom a property may occur from wells located in close proximity to suchproperty.

 

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**HEALTH,SAFETY, AND ENVIRONMENTAL REGULATION**

 

*General.*Activitieson the Underlying Properties are subject to existing Federal, state and locallaws and regulations governing health, safety, environmental quality andpollution control. It is anticipated that, absent the occurrence of anextraordinary event, compliance with existing Federal, state and local laws,rules and regulations regulating health, safety, the discharge of materialsinto the environment or otherwise relating to the protection of the environmentwill not have a material adverse effect upon the Trust. It cannot be predictedwhat effect additional regulation or legislation, enforcement policiesthereunder, and claims for damages to property, employees, other persons andthe environment resulting from operations on the Underlying Properties couldhave on the Trust. However, pursuant to the terms of the Conveyances, any costsor expenses incurred in connection with environmental liabilities of EasternAmerican arising out of or related to activities occurring on or in, orconditions existing on or under, the Underlying Properties before the effectivedate of the Conveyances will be borne by Eastern American and will not bededucted in calculating Net Proceeds attributable to the Net Profits Interests.Additionally, because Unitholders will have limited liability in accordancewith the Trust Agreement and Delaware law, Unitholders should be shielded fromdirect liability for any environmental liabilities. See “Description of TrustUnits and Depositary Units—Liability of Unitholders.” However, costs andexpenses incurred by Eastern American for certain Capital Costs associated withenvironmental liabilities arising after the effective date of the Conveyanceswould reduce Net Proceeds, and would therefore be borne, in part, by theUnitholders. The following subtopics discuss some of the principal forms ofhealth, safety, and environmental regulation to which the Underlying Propertiesand operations thereon are subject. The costs of complying with theseregulatory requirements may burden the Net Profits Interests to the extent theyarise out of or are related to activities occurring on or in, or conditionsexisting on or under, the Underlying Properties after the effective date of theConveyances.

 

* Solid and Hazardous Waste.*TheUnderlying Properties include numerous properties that have produced gas for anumber of years but in which Eastern American has held an interest for a relativelyshort period of time prior to the effective date of the Conveyances. EasternAmerican has informed us they have no knowledge of prior operators utilizingoperating and disposal practices that were not standard in the industry at thetime nor have hydrocarbons or other solid or hazardous wastes may have beendisposed of or released on or under the Underlying Properties. Federal, stateand local laws applicable to gas-related wastes have become increasingly morestringent. Under current laws, Eastern American or the operator of theUnderlying Properties could be required to remove or remediate previouslydisposed wastes or property contamination (including groundwater contamination)or to perform remedial plugging operations to prevent future contamination.

 

The operations of theUnderlying Properties may generate wastes that are subject to the FederalResource Conservation and Recovery Act (“RCRA”) and comparable state statutes.The Environmental Protection Agency (the “EPA”) has limited the disposaloptions for certain hazardous wastes and may adopt more stringent disposalstandards for nonhazardous wastes.

 

*Superfund.*The Comprehensive Environmental Response, Compensation andLiability Act (“CERCLA”), also known as the “superfund” law, imposes liability,regardless of fault or the legality of the original conduct, on certain classesof persons that contributed to the release of a “hazardous substance” into theenvironment. These persons include the current or previous owner and operatorof a site and companies that disposed or arranged for the disposal of, thehazardous substance found at a site. CERCLA also authorizes the EPA and, insome cases, private parties to take actions in response to threats to thepublic health or the environment and to seek recovery from such responsibleclasses of persons of the costs of such action. In the course of theiroperations, the operators of the Underlying Properties have generated and willgenerate wastes that may fall within CERCLA’s definition of “hazardous substances”.Eastern American or the previous operator of the Underlying Properties may beresponsible under CERCLA for all or part of the costs to clean up sites atwhich such substances have been disposed.

 

*AirEmissions.*The operations of the Underlying Properties aresubject to Federal, state and local regulations concerning the control ofemissions from sources of air contaminants. Administrative enforcement actionsfor failure to comply strictly with air regulations or permits are generallyresolved by payment of a monetary penalty and correction of any identifieddeficiencies. Regulatory agencies could require the operators to forego ormodify construction or operation of certain air emission sources.

 

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*OSHA.*Theoperations of the Underlying Properties are subject to the requirements of theFederal Occupational Safety and Health Act (“OSHA”) and comparable statestatutes. The OSHA hazard communication standard, the EPA communityright-to-know regulations under Title III of the Federal Superfund Amendmentand Reauthorization Act and similar state statutes require that information beorganized and maintained about hazardous materials used or produced in theoperations. Certain of this information must be provided to employees, stateand local government authorities and citizens.

 

**DESCRIPTIONOF TRUST UNITS AND DEPOSITARY UNITS**

 

The following informationis subject to the detailed provisions of the Deposit Agreement originallyentered into by Eastern American, the Trustee, and Bank of Montreal TrustCompany, as Depositary (the “Depositary”) and all holders from time to time ofDepositary Units (the “Deposit Agreement”), a copy of which is filed as anexhibit to this Form 10-K.

 

The functions of theDepositary under the Deposit Agreement are custodial and ministerial in natureand for the benefit of Unitholders. The Deposit Agreement and the issuance ofDepositary Units thereunder provide Unitholders an administratively convenientform of holding an investment in the Trust and a Treasury Obligation. EachDepositary Unit is evidenced by a certificate, which is issued by theDepositary and transferable only in denominations of 50 Depositary Units or anintegral multiple thereof. Accordingly, each holder of 50 Depositary Units ownsa beneficial interest in 50 Trust Units and the entire beneficial interest in adiscrete Treasury Obligation in a face amount of $1,000, or $20 per DepositaryUnit.

 

The deposited Trust Unitsand Treasury Obligations are held solely for the benefit of the Unitholders anddo not constitute assets of the Depositary or the Trust. The Depositary has nopower to assign, transfer, pledge or otherwise dispose of any of the TrustUnits or Treasury Obligations, except in the limited instances provided in theDeposit Agreement.

 

Generally, the holders ofDepositary Units are entitled to participate in distributions with respect tothe Trust Units, the Treasury Obligations and to the liquidation of theremaining assets of the Trust.

 

**Withdrawal of Trust Units andRestrictions on Transfer**

 

Upon presentation ofDepositary Units in denominations of 50 or integral multiples thereof forwithdrawal of the Trust Units and discrete Treasury Obligations evidencedthereby in accordance with the Deposit Agreement, the Unitholder will receivean uncertificated direct interest in Trust Units. These withdrawn Trust Unitswill be evidenced on the books of the Trustee by a transfer of such Trust Unitsfrom the name of the Depositary to the name of the withdrawing Unitholder.Holders of withdrawn Trust Units will be entitled to receive Trustdistributions and periodic Trust information (including tax information)directly from the Trustee. Moreover, holders of Trust Units will be entitled toeach of the rights accorded Unitholders under the Trust Agreement, includingvoting and liquidation rights, as elsewhere described herein, except thatwithdrawn Trust Units are not freely transferable as described below.

 

Pursuant to the TrustAgreement and the transfer application for transfer of the Trust Units,withdrawn Trust Units are not transferable except by operation of law. A holderof withdrawn Trust Units may, however, transfer such Trust Units indenominations of 50 (or integral multiples thereof) to the Depositary for redeposit,together with Treasury Obligations in the face amount equal to $1,000 for each50 Trust Units redeposited, in exchange for Depositary Units. Such redepositmay be effected by delivering written notice of such transfer jointly to theDepositary and the Trustee together with proper documentation necessary totransfer the requisite Treasury Obligations into the name of the Depositary.

 

**Distributions and IncomeComputations**

 

The Trustee determinesfor each quarter the Quarterly Distribution Amount available for distributionto holders of Depositary Units and the Trust Units evidenced thereby. TheQuarterly Distribution Amount is equal to the excess, if any, (i) the cash thatthe Trust receives on or before the tenth day of the third month after the endof each calendar quarter ending before the Trust is dissolved and that isattributable to production from the Net Profits Interest held by the Trustduring that calendar quarter, plus, with certain exceptions, any other cashreceipts of the Trust during such quarter, over (ii) the liabilities for theTrust paid during such quarter, subject to adjustments for changes made by theTrustee during

 

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such quarter in any cash reserves established for the payment of contingentor future obligations of the Trust. Based on the payment procedures relating tothe Net Profits Interests, cash received by the Trustee in a particular quarterfrom the Net Profits Interests reflects actual gas production for a portion ofsuch quarter and a production estimate for the remainder of such quarter, suchestimate to be adjusted to actual production in the following quarter. TheQuarterly Distribution Amount for each quarter is payable to Unitholders ofrecord on the Quarterly Record Date, which is the last day of the second monthfollowing the end of such calendar quarter or such later date as the Trusteedetermines is required to comply with legal or stock exchange requirements. TheTrustee generally is able to distribute cash on or before the 15th day (or thenext succeeding business day following such day if such day is not a businessday) of the third month following the end of each calendar quarter to eachperson who was a Unitholder of record on the Quarterly Record Date, together withinterest earned on such Quarterly Distribution Amount from the date of receiptthereof by the Trustee to the payment date.

 

The net taxableincome of the Trust for each calendar quarter is reported by the Trustee fortax purposes as belonging to the holders of record to whom the QuarterlyDistribution Amount was or will be distributed. Assuming that the Trust will beclassified for tax purposes as a “grantor trust,” the net taxable income willbe realized by the holders for tax purposes in the calendar quarter received bythe Trustee, rather than in the quarter distributed by the Trustee. Taxableincome of a holder may differ from the Quarterly Distribution Amount becausethe Treasury Obligations will be treated as generating interest income for taxpurposes. There may also be minor variances because of the possibility that,for example, a reserve will be established in one quarter that will not giverise to a tax deduction until a subsequent quarter, an expenditure paid for inone quarter will have to be amortized for tax purposes over several quarters. See“Federal Income Tax Matters”.

 

Each holder of DepositaryUnits (including the underlying Trust Units) of record as of the record datefor the final quarter of the Trust’s existence will be entitled to receive aliquidating distribution equal to a pro rata portion of the net proceeds fromthe sale of the Royalty NPI (to the extent not previously distributed) and apro rata portion of the proceeds from the matured Treasury Obligations.

 

**Possible Divestiture ofDepositary Units and Trust Units**

 

The TrustAgreement imposes no restrictions based on nationality or other status ofholders of Trust Units. However, the Trust Agreement and the Deposit Agreementprovide that in the event of certain judicial or administrative proceedingsseeking the cancellation or forfeiture of any property in which the Trust hasan interest because of the nationality, citizenship, or any other status, ofany one or more holders of Trust Units including holders of Depositary Units, theTrustee will give written notice thereof to each holder whose nationality,citizenship or other status is an issue in the proceeding, which notice willconstitute a demand that such holder dispose of his Depositary Units orwithdrawn Trust Units within 30 days. If any holder fails to dispose of hisDepositary Units or withdrawn Trust Units in accordance with such notice, cashdistributions on such units are subject to suspension. In the event a holderfails to dispose of Depositary Units in accordance with such notice, theDepositary may cancel such holder’s Depositary Units and reissue them in thename of the Trustee, whereupon the Trustee will use its reasonable efforts tosell the Depositary Units and remit the net sale proceeds to such holder. Inthe case of Trust Units withdrawn from deposit with the Depositary, the Trusteeshall redeem such Trust Units not divested in accordance with such notice, fora cash price equal to the then-current market price of the Depositary Unitsless the then-current over-the-counter bid price of the related, withdrawnTreasury Obligations. The redemption price will be paid out in quarterlyinstallments limited to the amount that otherwise would have been distributedin respect of such redeemed Trust Units.

 

**Liability of Unitholders**

 

Consistent with Delawarelaw, the Trust Agreement provides that the Unitholders will have the samelimitation on liability as is accorded under the laws of such state tostockholders of a corporation for profit. No assurance can be given, however,that a court would give effect to such limitation.

 

**Liquidation of the Trust**

 

The Trust will beliquidated and the Royalty NPI will be sold prior to the Liquidation Date,which is expected to occur in 2013. Unitholders of record as of the record datefor the final quarter of the Trust’s existence will be entitled to receive aterminating distribution with respect to each Depositary Unit equal to a prorata portion of the net proceeds from the sale of the Royalty NPI (to theextent not previously distributed) and a pro rata portion of the proceeds fromthe

 

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matured Treasury Obligations. Under the Trust Agreement, EasternAmerican has a right of first refusal to purchase the Royalty NPI at fairmarket value, or if applicable the offered third-party price, prior to theLiquidation Date.

 

**FEDERALINCOME TAX MATTERS**

 

This section is a summaryof Federal income tax matters of general application which addresses thematerial tax consequences of the ownership and sale of Depositary Units. Thissection provides a generalized summary of certain federal income tax matters ofgeneral application relating to ownership and sale of Depositary units byindividuals who are citizens or residents of the United States. Accordingly,the following discussion has only limited application to domestic corporationsand persons subject to specialized Federal income tax treatment, such astax-exempt entities (including IRAs), regulated investment companies andinsurance companies. The following discussion also does not address taxconsequences to foreign persons. It is impractical to comment on all aspects ofFederal laws that may affect the tax consequences of the transactionscontemplated hereby and of an investment in Depositary Units as they relate tothe particular circumstances of every prospective Unitholder. Each Unitholdershould consult his own tax advisor with respect to his particular circumstancesincluding, his alternative minimum tax circumstances.

 

This summary is based oncurrent provisions of the Internal Revenue Code of 1986, as amended (the “Code”),existing and proposed regulations thereunder and current administrative rulingsand court decisions, all of which are subject to changes that may or may not beretroactively applied. Some of the applicable provisions of the Code have notbeen interpreted by the courts or the Internal Revenue Service (“IRS”).

 

At the issuance of theDepositary Units, Eastern American obtained an opinion of counsel for thebenefit of the Trust, based on certain representations and subject to certainqualifications, that, for Federal income tax purposes, (a) the Trust will betaxed as a grantor trust and not as an association taxable as a corporation,(b) the Term NPI will be taxed as a production payment, (c) the income from theRoyalty NPI will be royalty income subject to the allowance for depletion, and(d) a Unitholder will be eligible to claim Section 29 Credits with respect tocertain sales of gas production attributable to the Royalty NPI. The Trusteehas reported the operations of the Trust consistent with these opinions.

 

No ruling has been orwill be requested from the IRS with respect to any matter affecting the Trustor Unitholders, and thus no assurance can be provided that the statements setforth herein (which do not bind the IRS or the courts) will not be challengedby the IRS or will be sustained by a court if so challenged.

 

**Reports**

 

Unitholders of record areprovided informational tax packages in order to permit computation of theirtaxable income from ownership of Depositary Units.

 

**Treatment of Depositary Units**

 

Purchasers of DepositaryUnits are treated, for Federal income tax purposes, as purchasing directly aninterest in the Treasury Obligations and a Trust Unit. Purchasers are thereforerequired to allocate the purchase price of their Depositary Unit between theinterest in the Treasury Obligations and the Trust Unit in the proportion thatthe fair market value of each bears to the fair market value of the Depositary Unit.Information regarding purchase price allocations is furnished to Unitholders bythe Trustee.

 

**Classification and Taxation ofthe Trust**

 

For federal income taxpurposes, the Trust has been treated and expects to continue to be treated notas an association taxable as a corporation, but as a grantor trust that is notsubject to Federal income tax as an entity separate from its beneficial owners.For tax purposes, Unitholders are considered to own and receive the Trust’sassets and income as though no trust were in existence. The Trust files aninformation return, reporting all items of income, credit or deduction whichmust be included in the tax returns of the Unitholders. If the Trust weredetermined not to be a grantor trust, it is expected that it would be treatedeither as a partnership subject to the publicly traded partnership rules underthe Code or as an association taxable as a corporation. If the Trust weretreated as a publicly traded partnership, it is believed that the Trust’svarious items of income and deduction would still be taxable to the Unitholderson a current, flow-through basis as partners of a partnership and not to theTrust as an association taxable as a corporation. If the Trust were determinedto be an association taxable as a corporation, it would be treated as aseparate entity subject to corporate

 

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tax on its taxable income, Unitholders would be treated asshareholders, and distributions to Unitholders from the Trust would be treatedas nondeductible corporate distributions. Such distributions would be taxableto a Unitholder, first, as dividends to the extent of the Unitholder’s pro ratashare of the Trust’s earnings and profits, then as a tax-free return of capitalto the extent of his basis in his Trust Units, and finally as capital gain tothe extent of any excess.

 

**Direct Taxation of Unitholders**

 

Assuming that theTrust is treated as a grantor trust for Federal income tax purposes, andUnitholders are treated for Federal income tax purposes as owning a directinterest in the Treasury Obligations and the assets of the Trust, eachUnitholder is taxed directly on his pro rata share of the income attributableto the Treasury Obligations and the assets of the Trust and is entitled toclaim his pro rata share of the deductions and credits attributable to theTrust (subject to certain limitations discussed below). Income, credits andexpenses attributable to the assets of the Trust and the Treasury Obligationsare taken into account by Unitholders consistent with their method ofaccounting and without regard to the taxable year or accounting method employedby the Trust.

 

The Trust makesquarterly distributions to Unitholders of record on each Quarterly Record Date.The terms of the Trust Agreement, as described below, seek to assure to theextent practicable that taxable income attributable to such distributions willbe reported by the Unitholder who receives such distribution, assuming that heis the owner of record on the Quarterly Record Date. In certain circumstances,however, a Unitholder will not receive the distribution attributable to suchincome. For example, if the Trustee establishes a reserve or borrows money tosatisfy liabilities of the Trust, income associated with the cash used toestablish that reserve or to repay that loan must be reported by theUnitholder, even though that cash is not distributed to him. In addition,Unitholders must recognize certain interest income attributable to the TreasuryObligations with respect to which no current cash distributions will be made.

 

The Trust allocatesincome, deductions and credits to Unitholders based on record ownership atQuarterly Record Dates. The IRS could require income and deductions of theTrust to be determined and allocated daily or require some method of dailyproration, which could result in an increase in the administrative expenses ofthe Trust.

 

Under current marketconditions, it is anticipated that total distributable cash will exceed taxableincome through 2005. After 2005, taxable income is anticipated to exceeddistributable cash, and the amount of such excess could be significant. Suchestimates are based on numerous assumptions as to the allocation of aUnitholder’s purchase price and the amount and treatment of operating costs,development costs, Trust administrative expenses, production estimates anddepletion. No assurance can be given that the estimates will prove to becorrect, and the actual relationship between distributable cash and taxableincome could be materially different.

 

**Treatment of Trust Units**

 

On the assumption thatthe Trust is a grantor trust for Federal income tax purposes, each Unitholderis treated as purchasing directly an interest in the Net Profits Interests.Purchasers of Depositary Units must allocate the portion of their totalpurchase price allocated to the Trust Unit between the Royalty NPI and the TermNPI in the proportion that the fair market value of each bears to the totalfair market value of both. Information regarding purchase price allocations isfurnished to Unitholders by the Trustee.

 

**Interest Income**

 

The Term NPI is treatedas a “production payment” under Section 636(a) of the Code. Thus, Unitholdersare treated as making a mortgage loan on the Underlying Properties of the TermNPI to Eastern American in an amount equal to the amount of the purchase priceof each Depositary Unit allocated to the Term NPI. Because it is treated as adebt instrument for tax purposes, the Term NPI is subject to the original issuediscount income (“OID”) rules of the Code which generally require the periodicinclusion of the original issue discount in income of the purchaser of a debtinstrument. The Code also authorizes the IRS to prescribe regulations modifyingthe statutory provisions where, by reason of contingent payments such as thoseprovided for by the Term NPI, the tax treatment provided under the Codeprovisions does not carry out the purposes of such provisions.

 

The IRS has issued aseries of proposed and final regulations dealing with debt instruments whichcall for contingent payments. The initial set of proposed regulations dealingwith this topic were issued on April 8, 1986, and modified on February 26, 1991(the “Old Proposed Regulations”). A second set of proposed contingent payment

 

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regulations were issued on January 19, 1993, but were withdrawn priorto publication in the Federal Register. On December 15, 1994, the IRS replacedthe Old Proposed Regulations by issuing a third set of proposed regulationsaddressing debt obligations that provide for contingent payments (the “NewProposed Regulations”). The New Proposed Regulations were proposed to beeffective for debt obligations issued on or after the date that is sixty daysfollowing the promulgation of the New Proposed Regulations in final form. Inthis regard, the New Proposed Regulations have been adopted in final form (the “FinalRegulations”), though effective only for debt instruments issued after August12, 1996. Thus, by their terms, the New Proposed Regulations and the FinalRegulations do not apply to the Term NPI. However, the Preamble to the FinalRegulations provides that for debt instruments issued prior to the effectivedate of the Final Regulations, a taxpayer may use any reasonable method toaccount for such debt instruments, including a method that would have beenpermitted under the proposed regulations when the debt instrument was issued.

 

The Trustee understandsthat, in accordance with the foregoing, Eastern American, as obligor under theTerm NPI, intends to continue to treat the Term NPI in the manner providedunder the Old Proposed Regulations, which were proposed at the time the TermNPI was transferred to the Trust and Trust Units were issued. Under thisapproach, each payment (at the time the amount of such payment becomes fixed)made to the Trust with respect to the Term NPI will be treated first as apayment of interest to the extent of interest deemed accrued under the OIDrules and the excess (if any) will be treated as a payment of principal. Thetotal amount treated as principal will be limited to a portion of the purchaseprice of each Depositary Unit allocated to the Term NPI. For purposes ofdetermining the amount of accrued interest, the Old Proposed Regulationsrequired the use of the Applicable Federal Rate based on the due date of thefinal payment due under the terms of the production payment, which for the TermNPI is May 15, 2013.

 

Unitholders are alsorequired to recognize and report OID interest income attributable to theTreasury Obligations. In general, the total amount of OID a Unitholder isrequired to recognize will be calculated as the difference between the amountof the purchase price of a Depositary Unit allocated to the TreasuryObligations and the pro rata portion of the face amount of such TreasuryObligations attributable to the Depositary Unit. The amount of OID socalculated is included in income by a Unitholder on the basis of a constantinterest rate computation.

 

**Royalty Income and Depletion**

 

The income from theRoyalty NPI is royalty income subject to an allowance for depletion. Thedepletion allowance must be computed separately by each Unitholder for each oilor gas property (within the meaning of Code Section 614). The IRS presentlytakes the position that a net profits interest burdening multiple properties isone property for depletion purposes. Accordingly, the tax information reportsthat the Trust provides to Unitholders and the IRS have reported all productionattributable to the Royalty NPI as production attributable to a single propertyfor depletion purposes. Such reporting treatment is expected to continue untilat least the IRS position on such treatment is changed.

 

The allowance fordepletion with respect to a property is determined annually and is the greaterof cost depletion or, if allowable, percentage depletion. Percentage depletionis generally available to “independent producers” (generally persons who arenot substantial refiners or retailers of oil or gas or their primary products)on the equivalent of 1,000 barrels of production per day. Percentage depletionis a statutory allowance equal to 15% of the gross income from production froma property which is included in income by a taxpayer.

 

Percentage depletion issubject to a net income limitation which is 100% of the taxable income from theproperty, computed without regard to depletion deductions and certain losscarrybacks. A taxpayer’s total percentage depletion deduction for allproperties for a taxable year is limited to 65% of the taxpayer’s taxableincome for the year, before percentage depletion and certain other deductions.Unlike cost depletion, percentage depletion is not limited to the adjusted taxbasis of the property, although it reduces that adjusted tax basis (but notbelow zero).

 

In computing costdepletion for each property for any year, the adjusted tax basis of thatproperty at the end of that year is divided by the estimated total units (Mcfof gas) recoverable from that property to determine the per-unit allowance forsuch property. The per-unit allowance is then multiplied by the number of unitsproduced and sold from that property during the year. Cost depletion for aproperty cannot exceed the adjusted tax basis of such property. While the Trustis treated as a grantor trust for Federal income tax purposes, each Unitholdercomputes cost depletion by using as his basis for the property the portion ofhis cost basis for his Depositary Units that is allocated first to the NPI andsecond to the Royalty NPI. Information is provided by the Trustee to eachUnitholder reflecting how that basis should be allocated.

 

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**Section 29 Credit**

 

The Trustee has beeninformed by Eastern American that most of the production attributable to theRoyalty NPI is gas produced from Devonian shale or a tight formation. Provideda number of requirements are met, taxpayers are entitled to the Section 29Credit for gas produced from Devonian shale or a tight formation. The Section29 Credit generally applies only to gas produced from Devonian shale or a tightformation in the United States and sold to an unrelated party prior to January1, 2003, from wells drilled after December 31, 1979, and prior to January 1,1993. Additionally, the Section 29 Credit applies only to gas produced from atight formation which, as of April 20, 1977, was committed or dedicated tointerstate commerce (as defined in Section 2(18) of the Natural Gas Policy Act,as in effect on November 5, 1990), or which is produced from a well drilledafter November 5, 1990. A Unitholder is eligible to claim the Section 29 Creditwith respect to certain sales of such gas attributable to the Royalty NPI. Undercurrent law, the Section 29 credit is no longer available for production afterDecember 31, 2002.

 

Section 29 Creditsresulting from an investment in Depositary Units may only be used to reduce ataxpayer’s regular income tax liability and generally may not be used to reducea taxpayer’s liability for alternative minimum tax. Section 29 Creditsavailable to a taxpayer in any taxable year may not be carried back but may becarried forward for use by that taxpayer in a subsequent tax year only in alimited fashion. See “Alternative Minimum Tax” below.

 

The Section 29 Credit isnot available for production after December 31, 2002. Congress in past yearshas considered, without enacting, legislation to extend energy tax credits suchas the Section 29 Credit beyond their expiration date or to create new similarcredits. The potential effect that enactment of any such possible legislationmay have on Unitholders in the future is unknown.

 

On March 23, 1999, the United States Tax Court ofAppeals for the Tenth Circuit affirmed a lower court decision in *True Oil Company v.*C.I.R. 170F.3d 1294. The Court ruled that, in order to be eligible for credits underSection 29 of the Internal Revenue Code, each well from which gas is producedfrom Devonian shale or a tight formation must receive a determination from theFederal Energy Regulatory Commission (“FERC”) that the gas produced is, infact, produced from Devonian shale or a tight formation. Eastern American hasverified that most producing gas wells subject to the Royalty NPI have receiveda well category determination from FERC. Should the Internal Revenue Servicechallenge the amount of the Trust’s production qualifying for Section 29Credits, a Unitholder might not be able to claim the benefit of Section 29credits for production attributable to a well that did not receive a FERCdetermination. If successful, such a challenge could affect the tax reportingfor such credits for tax years examined by the IRS and any subsequent tax years.However, it should be noted that under current law the Section 29 credit is nolonger available for production after December 31, 2002.

 

**Other Income and Expenses**

 

From time to time, theTrust may generate interest income on funds held as a reserve or held until thenext distribution date. Expenses of the Trust include administrative expensesof the Trustee. Under the Code, certain miscellaneous itemized deductions of anindividual taxpayer are deductible only to the extent that in the aggregatethey exceed 2% of the taxpayer’s adjusted gross income. Certain administrativeexpenses attributable to the Trust Units may have to be aggregated with anindividual Unitholder’s other miscellaneous itemized deductions to determinethe excess over 2% of adjusted gross income. To date the amount of suchexpenses has not been significant in relation to the Trust’s income.

 

**Alternative Minimum Tax**

 

The Code imposes aminimum tax (known as an “alternative minimum tax” or “AMT”) on each taxpayerto the extent that his “tentative minimum tax” in any taxable year exceeds hisregular tax for that year. For purposes of computing the AMT, the taxpayer’staxable income is recomputed with various “adjustments” plus “items of taxpreference”.

 

A taxpayer is generallyentitled to a credit against, or reduction in, his regular tax liability in asubsequent year in an amount equal to the AMT he pays for a prior taxable year.However, that credit can only be used to reduce his regular tax liability forthat subsequent year to the extent his regular tax liability for thatsubsequent year exceeds his tentative minimum tax liability for that subsequentyear.

 

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The Section 29 Creditallowable to a taxpayer as a reduction of his tax liability for any priortaxable year could not have exceeded the excess of his regular tax liabilityfor such taxable year, as reduced by his foreign tax credits and certainnonrefundable credits, over his tentative minimum tax liability for that year.Any amount of Section 29 Credit disallowed for the prior tax year solelybecause of this limitation will increase a taxpayer’s credit for the prior year’sAMT, as described above. There is no provision for the carryback orcarryforward of the Section 29 Credit in any other circumstances. Therefore, aUnitholder may not have received the full benefit of available Section 29Credits, depending on his particular AMT circumstances. However, it should benoted that under current law the Section 29 credit is no longer available forproduction after December 31, 2002.

 

Since the effect of theAMT varies depending upon each Unitholder’s personal tax and financialposition, each Unitholder is advised to consult with his, her or its own taxadvisor concerning the effect of the AMT and Section 29 Credits attributable toan investment in the Depositary Units.

 

**Non-Passive Activity**

 

The income, credits andexpenses of the Trust are not taken into account in computing the passiveactivity losses and income under Code Section 469 for a Unitholder who acquiresand holds Depositary Units as an investment and did not acquire them in theordinary course of business.

 

**Unrelated Business Taxable Income**

 

Certain organizationsthat are generally exempt from tax under Code Section 501 are subject to tax oncertain types of business income defined in Code Section 512 as unrelatedbusiness income. The income of the Trust is not unrelated business taxableincome within the meaning of Code Section 512 so long as the Trust Units arenot “debt-financed property” within the meaning of Code Section 524(b). Ingeneral, a Trust Unit would be debt-financed if the Unitholder incurs debt toacquire a Trust Unit or otherwise incurs or maintains a debt that would nothave been incurred or maintained if such Trust Unit had not been acquired.Legislative proposals have been made from time to time which, if adopted, wouldresult in the treatment of income attributable to the Royalty NPI as unrelatedbusiness income.

 

**Sale of Depositary Units; Sale ofTrust Units or Treasury Obligations**

 

Generally, a Unitholderwill realize gain or loss on the sale or exchange of his Depositary Unitsmeasured by the difference between the amount realized on the sale or exchangeand his adjusted basis for such Depositary Units. Gain or loss on the sale ofDepositary Units by a Unitholder who is not a dealer with respect to suchDepositary Units and who has a holding period for the Depositary Units of more thanone year will be treated as long-term capital gain or loss, except to theextent of the depletion recapture amount and any accrued market discount asexplained below. A Unitholder’s initial basis in his Depositary Units is equalto the amount paid for such Depositary Units. Such basis is increased by theamount of OID income recognized by the Unitholder attributable to the TreasuryObligations. Such basis is reduced by deductions for depletion claimed by theUnitholder (but not below zero). In addition, such basis is reduced by theamount of any payments attributable to the Term NPI which are treated aspayments of principal under the OID rules.

 

For Federal income taxpurposes, the sale of a Depositary Unit is treated as a sale by the Unitholderof his interest in the Treasury Obligations and the assets of the Trust. Thus,upon the sale of Depositary Units, a Unitholder must treat as ordinary incomehis depletion recapture amount, which is an amount equal to the lesser of (i)the gain on that sale attributable to disposition of the Royalty NPI or (ii)the sum of the prior depletion deductions taken with respect to the Royalty NPI(but not in excess of the initial basis of such Depositary Units allocated tothe Royalty NPI). It is possible that the IRS would take the position that aportion of the sales proceeds is ordinary income to the extent of any accruedincome at the time of sale allocable to the Depositary Units sold, but which isnot distributed to the selling Unitholder.

 

A Unitholder who allocateshis purchase price (or is required to allocate his purchase price) to theTreasury Obligations in an amount less than the sum of (a) his share of theinitial issue price of the Treasury Obligations and (b) his share of OID incomerecognized by prior holders of the Treasury Obligations (any such differencerepresents “market discount”) will generally be required to recognize ordinaryincome to the extent of any accrued market discount upon sale of the DepositaryUnits. In general, accrued market discount is an amount which bears the sameratio to total market

 

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discount as the number of days which a Unitholder holds a DepositaryUnit bears to the number of days after the date the Unitholder acquired theDepositary Unit and up to and including the Liquidation Date.

 

**Withdrawal of Trust Units orTreasury Obligations**

 

A Unitholder willrecognize no gain or loss upon the withdrawal of the Trust Units or TreasuryObligations from the Depositary. A sale of the Trust Units or the TreasuryObligations will result in the recognition of income or loss.

 

**Sale of Net Profits Interests orProduction Payment**

 

A sale by the Trust ofNet Profits Interests are treated for Federal income tax purposes as a sale ofNet Profits Interests by a Unitholder. Thus, a Unitholder will recognize gainor loss on a sale of Net Profits Interests by the Trust. A portion of thatincome may be treated as ordinary income to the extent of depletion recapture.Receipt by the Trust of proceeds drawn from the letter of credit supportingEastern Marketing’s obligations under the Gas Purchase Contract is, in certaincases, in consideration for the conveyance to Eastern Marketing of a productionpayment interest in reserves attributable to the Net Profits Interests or tocompensate the Trust for damages from a breach of the Gas Purchase Contract.All or a portion of such proceeds may be treated as non-taxable loan proceedsattributable to a loan by Eastern Marketing resulting from the production payment,may be treated as ordinary income not subject to depletion or may receive someother treatment, depending upon facts existing at that time. To the extentreceipt of such proceeds is attributable to a sale of reserves by the Trust,depletion and Section 29 Credits available to the Unitholders for subsequentperiods is reduced.

 

**Backup Withholding**

 

In general, distributionsof Trust income are not subject to “backup withholding” unless (i) theUnitholder is an individual or other noncorporate taxpayer and (ii) suchUnitholder fails to comply with certain reporting procedures.

 

**Tax Shelter Registration**

 

The Trust has beenregistered with the IRS as a “tax shelter,” and has received tax shelterregistration number 93040000163. A “tax shelter,” for purposes of theregistration requirement, is an investment with respect to which a person couldreasonably infer, from the representations made in connection with any offerfor sale of any interest in the investment, that the “tax shelter ratio” forany investor may be greater than two to one as of the close of any of the firstfive years ending after the date on which the investment is offered for sale.The term “tax shelter ratio” with respect to an investment means the ratio thatthe aggregate amount of gross deductions for any investor, determined withoutregard to income derived from the investment, plus 350% of the credits that arepotentially available to an investor, bears to the investment base for theyear. The “investment base” is equal to the cash, plus the adjusted basis(which may be less than the fair market value) of any other property invested.Certain borrowings, however, including those from other participants in theventure, are excluded from the investment base. While Eastern American has noknowledge of any such borrowings, it is possible that, due to such borrowings,the investment base of an investor would be substantially reduced oreliminated.

 

A Unitholder who sells orotherwise transfers a Trust Unit must furnish to the transferee the tax shelterregistration number set forth above. The penalty for failure of the transferorof a Trust Unit to furnish such tax shelter registration number to a transfereeis $100 for each such failure. Unitholders must disclose the tax shelterregistration number of the Trust on Form 8271 to be attached to the tax returnon which any deduction, loss, credit or other benefit generated by the Trust isclaimed or income of the Trust is included. A Unitholder who fails to disclosethe tax shelter registration number on his return, without reasonable cause forsuch failure, will be subject to a $250 penalty for each such failure. (Anypenalties discussed herein are not deductible for income tax purposes.)

 

**ISSUANCEOF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THIS INVESTMENT OR THECLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.**

 

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**STATE TAXCONSIDERATIONS**

 

The following is intendedas a brief summary of certain information regarding state income taxes andother state tax matters affecting individual Unitholders. Unitholders are urgedto consult their own legal and tax advisors with respect to these matters.

 

The Trust owns the NetProfits Interests burdening the Underlying Properties located in the states ofPennsylvania and West Virginia. Both of these states have income taxesapplicable to individuals and may require the Trust to withhold taxes fromdistributions made to nonresident Unitholders. Withholding, if required, is atthe rate of 4% of taxable income attributable to West Virginia and 3.07% oftaxable income attributable to Pennsylvania. A Unitholder may be required tofile state income tax returns and/or to pay taxes in these states and may besubject to penalties for failure to comply with such requirements. Generally,Unitholders may treat state income taxes that the Trust has withheld as havingbeen paid by them to the state for which they were withheld. Unitholders may beable to treat any taxes that they have paid or that have been withheld and paidto West Virginia or Pennsylvania as a deduction in computing Federal incometax, or as a credit or a deduction in computing another state’s income tax.

 

Unitholders receiveinformation concerning the Depositary Units and the Trust Units sufficient toidentify the income from Depositary Units that is allocable to each state.Holders of Depositary Units should consult their own tax advisors to determinetheir income tax filing requirements with respect to their share of income of theTrust allocable to states imposing a tax on such income.

 

The Trust Units andtherefore also the Depositary Units may constitute real property or an interestin real property under the tax, inheritance, estate and probate laws of eitheror both of Pennsylvania and West Virginia. If the Depositary Units are held tobe real property or an interest in real property under the laws of a state inwhich the Underlying Properties are located, the holders of Depositary Unitsmay be subject to ad valorem or other property tax, devolution, probate andadministration laws, and inheritance or estate and similar taxes, under thelaws of such state.

 

**Available Information**

 

The Trust does notmaintain an internet address or a website, and therefore does not make copies ofits reports under the Exchange Act available in that manner. The Trust’sfilings under the Exchange Act are available electronically from the websitemaintained by the Securities and Exchange Commission at http://www.sec.gov. TheTrust will also provide electronic copies of its recent filings free of chargeupon request to the Trustee, and will provide paper copies of its recentfilings for its costs of reproduction upon request to the Trustee.

 

**Item****1A. *Risk Factors***

 

Following is a summary of the principal risksassociated with an investment in Units in the Trust.

 

**Natural gas prices fluctuate dueto a number of factors, and lower prices will reduce net proceeds to the Trustand distributions to Unitholders**.

 

The Trust’s revenues and distributions to Unitholdersare highly dependent on the sales prices as reflected in the Henry Hub AveragePrice, as defined in the Gas Purchase Contract, and on the quantities ofnatural gas attributable to the Net Profits Interests. Prices for natural gascan fluctuate widely in response to a number of factors that are beyond thecontrol of Eastern American and the Trust. These factors include:

 

worldwide economic conditions;

weather conditions;

changes and expectations regarding natural gasproduction and transportation;

levels of actual and anticipated demand;

price and availability of alternative fuels;

the availability of gathering, transportation and processing facilities; and

the effects of worldwide energy conservation measures.

 

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**Low gas prices may reduceproduction**.

 

Low natural gas prices may reduce the amount of gasthat is economic to produce. As a result, the operator could determine duringperiods of low gas prices to shut in or curtail production. In addition, theoperator could determine during periods of low gas prices to plug and abandonmarginal wells.

 

**Estimated reserves and futureproduction levels are uncertain.**

 

The value of the Depositary Units depends on, amongother things, the proved reserves and production levels attributable to the NetProfits Interests. There are many uncertainties involved in estimatingquantities and values of proved reserves and in projecting future rates ofproduction. The reserve data included in this Annual Report are estimates only,and actual quantities and values of natural gas are likely to differ from theestimated amounts. The discounted present values shown for the Net ProfitsInterests were prepared using guidelines established by the SEC for disclosureof reserves and should not be considered representative of market value.

 

**There are risks inherent in thedevelopment and production of natural gas.**

 

Distributions to Unitholders could be adverselyaffected if any of the risks typically associated with the development, productionand transportation of natural gas were to occur, including personal injuries,property damage, well damage and damage to productive formations or equipment.

 

**None of the Trust, the Trusteenor the Unitholders has any control over the operation of the properties.**

 

None of the Trust, Trustee nor the Unitholders is ableto influence or control the operation of the properties. All of the wells areoperated by Eastern American. As operator, Eastern American has the right toabandon or sell any well if, in its opinion, the well or property ceases toproduce or is not capable of producing in commercially paying quantities. Ingeneral, upon abandonment of any well to which the Net Profits Interestsrelate, that portion of the Net Profits Interests will be extinguished.

 

**Gas reserves are depletingassets.**

 

Gas reserves are depleting assets. The reservesattributable to the Net Profits Interests have declined and are expected tocontinue to decline over time. The accreting value of the Treasury Obligationsmay not fully offset the depletion of the reserves attributable to the NetProfits Interests.

 

**Compliance with governmentregulation may be expensive.**

 

The production, transportation and sale of natural gasfrom the wells to which the Net Profits Interest relate are subject to

 

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governmental regulation. Compliance with these regulations may beexpensive.

 

**Operating costs, capitalexpenditures and taxes reduce payments to the Trust.**

 

The operating costs charged in calculating NetProceeds include a fixed charge, subject to increase of up to 5% annually. Inaddition, property and production taxes and certain capital expenditures arededucted from gross proceeds in determining the Net Proceeds. In general, increasesin chargeable costs will have the effect of reducing the amount of NetProceeds.

 

**Increased administrative costsreduce distributions to Unitholders.**

 

Administrative costs, including professional servicesfees and expenses, are deducted prior to distributions to Unitholders.Consequently, increases in administrative costs adversely affect distributionsto Unitholders.

 

**The Ensource exchange offer mayresult in additional increased administrative costs.**

 

As described elsewhere in this Annual Report on Form10-K, in November 2005 Ensource Energy Income Fund LP commenced an unsolicitedexchange offer in an effort to acquire control of the Trust. The Trust hasincurred substantially increased administrative costs as a result of theEnsource exchange offer, and may continue to do so for the duration of theEnsource exchange offer. All costs incurred by the Trust in connection with theEnsource offer decrease distributions to Unitholders.

 

**The legal status of the NetProfits Interests under some circumstances is unclear.**

 

 At the time ofthe formation of the Trust, Eastern American noted that it was likely that theNet Profits Interests would not be treated as real property interests under thelaws of West Virginia and Pennsylvania. Nevertheless, Eastern American recordedthe Conveyances in the real property records of West Virginia and Pennsylvaniain accordance with local recording acts. Eastern American believes that, if,during the term of the Trust, Eastern American becomes involved as a debtor ina bankruptcy proceeding under the Federal Bankruptcy Code, the Net ProfitsInterests relating to the Underlying Properties located in West Virginia wouldbe treated as fully conveyed personal property interests. However, if theConveyances were held to constitute executory contracts, and if such contractswere not to be assumed in a bankruptcy proceeding, the Trust probably would betreated as an unsecured creditor of Eastern American. With respect to theproperties located in Pennsylvania, which represented approximately 10% of thereserves attributable to the Net Profits Interests at the inception of theTrust, Eastern American believed that there is a greater risk that the NetProfits Interests would not be treated as fully conveyed property interests andinstead the Conveyances could be treated as executory contracts, meaning thatthe Trust could be treated as an unsecured creditor with respect to thoseinterests.

 

**The Net Profits Interests aresubject to any defects in Eastern American’s rights to the Underlying Properties.**

 

The Net Profits Interests are subject to any defectsin Eastern American’s rights with respect to the Underlying Properties. EasternAmerican believes that its interests with respect to the Underlying Propertiesare good and defensible in accordance with standards generally accepted in theAppalachian oil and gas industry, subject to exceptions which do not detractsubstantially from the value of its interests. However, it is possible thatleases or farmout agreements could be treated as executory contracts if thethird party lessor or farmor under a farmout agreement were to become a debtorin bankruptcy, meaning that it is possible that a lease or farmout agreementcould be rejected in a bankruptcy proceeding.

 

**The opinion of tax counsel obtainedat inception of the Trust is not binding on the IRS or any court.**

 

At the inception of the Trust, Eastern Americanreceived an opinion of counsel that the Trust is a grantor trust and not anassociation taxable as a corporation for Federal income tax purposes, and thateach Unitholder would be taxed directly on his pro rata share of the incomeattributable to assets of the Trust and, subject to certain limitations, wouldbe entitled to claim depletion deductions and tax credits attributable to theRoyalty NPI and would be entitled to claim his pro rata share of otherdeductions attributable to assets of the Trust. However, the opinion of counselis not binding on the IRS or any court.

 

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**Taxable income could exceed cashdistributions.**

 

It is possible that taxable income per Depositary Unitmay exceed cash distributions per Depositary Unit. In addition, to the extentthat distributable cash is used to establish Trust reserves or to repayborrowed funds, Unitholders will recognize taxable income without receiving thecash used to establish reserves or to repay borrowed funds.

 

**Eastern American and the Trustmay have conflicts of interest.**

 

The interests of Eastern American and the interests ofthe Trust and the Unitholders may at times be different. For example, EasternAmerican’s interests may conflict with those of the Trust and Unitholders insituations involving the development, operation or abandonment of theUnderlying Properties or adjacent properties. In making decisions with respectto such operations, or otherwise with respect to the development, operation orabandonment of the Underlying Properties, Eastern American is required to actas a reasonably prudent operator in the Appalachian Basin would act withrespect to its own properties, without regard to the existence of the NetProfits Interests and without regard to any possible adverse effect on EasternMarketing or Eastern American under the Gas Purchase Contract. In addition,Eastern American has agreed not to drill any well within 1,000 feet of any wellsubject to the Net Profits Interests which produces oil or gas from thesame  formations or horizons as any suchproducing well. These covenants would not prohibit Eastern American fromdrilling additional wells on the same property as the wells subject to the NetProfits Interests provided that Eastern American complies with both of thesecovenants. In addition, these covenants would not prohibit Eastern Americanfrom drilling development wells on adjacent properties provided that EasternAmerican complies with the 1,000 foot limitation. If Eastern American ispermitted under these covenants to drill additional development wells near thewells subject to the Net Profits Interests, the additional wells could causedrainage of the reserves attributable to the Net Profits Interests. Thesecovenants apply only to Eastern American, and do not apply to third parties.

 

In addition, Eastern American’s interests may conflictwith those of the Trust and the Unitholders in situations involving the sale ofUnderlying Properties. Eastern American has the right to sell all or anyportion of the Underlying Properties without restrictions; however, except inlimited circumstances where Eastern American may require the Trust to releasethe Net Profits Interests, the Conveyances provide that the purchaser of any ofthe Underlying Properties will acquire such Underlying Properties subject tothe Net Profits Interests. The Conveyances provide that a purchaser will be subjectto the same standards of conduct with respect to development, operation andabandonment of such Underlying Properties as are applicable to EasternAmerican. Eastern American has the right, subject to limitations, to cause theTrust to release a portion of the Net Profits Interests in connection with asale of a portion of the Underlying Properties.

 

**Unitholders have only limitedvoting rights.**

 

While Unitholders have certain voting rights pursuantto the terms of the Trust Agreement, these rights are more limited than thoseof stockholders of most corporations. For example, there is no requirement forannual meetings of Unitholders or for an annual or other periodic re-electionof the Trustee.

 

**Unitholders could be subject tounlimited liability.**

 

Consistent with Delaware law, the Trust Agreementprovides that the Unitholders will have the same limitation on liability as isaccorded under the laws of such state to stockholders of a corporation forprofit. No assurance can be given, however, that the courts in jurisdictionsoutside of Delaware will give effect to such limitation.

 

**There are risks associated withthe financial position of Eastern American**

 

Eastern American is a privately held, independentenergy company engaged primarily in the exploration, development, production,transportation and marketing of natural gas within the Appalachian Basin. Theability of Eastern Marketing and Eastern American to perform their obligationsunder the Gas Purchase Contract depends on their financial condition, which inturn depends upon the supply and demand for natural gas, economic conditionsand upon financial, business and other factors, many of which are beyond thecontrol of Eastern American.

 

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**Noneof the Trustee, the Trust nor the Unitholders has any control over theoperation of the Underlying Properties.**

 

None of the Trustee, theTrust nor the Unitholders has any influence or control over the operation ofthe Underlying Properties, all of which are operated by Eastern American.

 

**Item 1B.*Unresolved Staff Comments.***

 

None.

 

**Item 2.   *****Properties****.*

 

Reference is made to Item1 of this Form 10-K.

 

**Item 3.   *****Legal Proceedings****.*

 

None.

 

**Item 4.   *Submission of Matters to aVote of Unitholders****.*

 

None.

 

**PART II**

 

**Item 5.****           *Market forthe Registrant’s Common Equity, Related Unitholders Matters and IssuerPurchases of Equity Securities .***

 

The Depositary Units aretraded on the New York Stock Exchange under the ticker symbol “NGT”. The highand low prices and distributions paid during the quarters in the three-yearperiod ended December 31, 2005 were as follows:

 
| **Quarter**                   | ** ** | **High** | ** ** | **Low** | ** ** | **Distributions  Paid** | ** ** |
|-------------------------------|------------|----------|------------|---------|------------|-------------------------|------------|
| 2003:                         |       |     |       |    |       |                    |       |
| First (to March 31, 2003)     |       | $        | 19.58      |    | $          | 18.70                   |       | $ | 0.38 |   |
| Second (to June 30, 2003)     |       | $        | 22.28      |    | $          | 18.87                   |       | $ | 0.52 |   |
| Third (to September 30, 2003) |       | $        | 23.55      |    | $          | 20.83                   |       | $ | 0.51 |   |
| Fourth (to December 31, 2003) |       | $        | 26.03      |    | $          | 22.10                   |       | $ | 0.41 |   |
|                          |       |     |       |    |       |                    |       |
| 2004:                         |       |     |       |    |       |                    |       |
| First (to March 31, 2004)     |       | $        | 27.40      |    | $          | 22.95                   |       | $ | 0.43 |   |
| Second (to June 30, 2004)     |       | $        | 23.80      |    | $          | 20.95                   |       | $ | 0.49 |   |
| Third (to September 30, 2004) |       | $        | 25.65      |    | $          | 23.41                   |       | $ | 0.48 |   |
| Fourth (to December 31, 2004) |       | $        | 27.00      |    | $          | 24.75                   |       | $ | 0.62 |   |
|                          |       |     |       |    |       |                    |       |
| 2005:                         |       |     |       |    |       |                    |       |
| First (to March 31, 2005)     |       | $        | 28.90      |    | $          | 24.40                   |       | $ | 0.50 |   |
| Second (to June 30, 2005)     |       | $        | 28.11      |    | $          | 25.45                   |       | $ | 0.51 |   |
| Third (to September 30, 2005) |       | $        | 31.58      |    | $          | 27.62                   |       | $ | 0.64 |   |
| Fourth (to December 31, 2005) |       | $        | 31.20      |    | $          | 26.75                   |       | $ | 0.67 |   |

 

At February 28, 2006, the5,900,000 Depositary Units outstanding were held by approximately 241Unitholders of record.

 

22

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With respect to theTreasury Obligations, the high and low closing prices per $1,000 face amountfor the period from January 1, 2005 to December 31, 2005 were $735.45 and $684.40,respectively. The closing price on December 31, 2005 was $722.26 per $1,000face amount.

 

Duringthe fourth quarter of 2005, there were no purchases of Units made by or onbehalf of the Trust or any “affiliated purchaser” as defined in Rule 10b-18 (a)(3) under the Exchange Act.

 

**Item 6.****    *Selected Financial Data.***

 
| ** **                    | ** ** | **December  31, 2005** | ** ** | **December  31, 2004** | ** ** | **December  31, 2003** | ** ** | **December  31, 2002** | ** ** | **December  31, 2001** | ** ** |
|-------------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| Royalty Income                |       | $                           | 18,179,459 |                        | $          | 14,449,208                  |       | $                           | 13,177,510 |                        | $          | 9,024,646 |   | $ | 13,260,202 |   |
| Distributable Income          |       | $                           | 14,597,387 |                        | $          | 12,019,847                  |       | $                           | 10,947,816 |                        | $          | 7,808,725 |   | $ | 11,268,383 |   |
| Distribution Amount           |       | $                           | 13,712,387 |                        | $          | 11,919,847                  |       | $                           | 10,732,816 |                        | $          | 7,808,725 |   | $ | 11,268,383 |   |
|                          |       |                        |       |                        |       |                        |       |                        |       |                        |       |
| Distributable Income per unit |       | $                           | 2.47       |                        | $          | 2.04                        |       | $                           | 1.86       |                        | $          | 1.32 |   | $ | 1.91 |   |
| Distribution Amount per unit  |       | $                           | 2.32       |                        | $          | 2.02                        |       | $                           | 1.82       |                        | $          | 1.32 |   | $ | 1.91 |   |
|                          |       |                        |       |                        |       |                        |       |                        |       |                        |       |
| Total assets at year end      |       | $                           | 32,954,834 |                        | $          | 35,000,087                  |       | $                           | 37,436,640 |                        | $          | 41,006,654 |   | $ | 45,129,170 |   |

 

**Item 7.    *Management’s Discussion and Analysis ofFinancial Condition and Results of Operations****.*

 

**General**

 

The Trust does notconduct any operations or activities. The Trust’s purpose is, in general, tohold the Net Profits Interests, to distribute to Unitholders cash which theTrust receives in respect of the Net Profits Interests and to perform certainadministrative functions in respect of the Net Profits Interests and theDepositary Units. The Trust derives substantially all of its income and cashflows from the Net Profits Interests.

 

Under the Gas PurchaseContract, Eastern Marketing purchases gas from the Trust at a variable pricefor any quarter equal to the Henry Hub Average Spot Price (as defined) perMMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment forBtu content. The Henry Hub Average Spot Price is defined as the price per MMBtudetermined for any calendar quarter equal to the price obtained with respect toeach of the three months in such quarter, in the manner specified below, andthen taking the average of the prices determined for each of such three months.The price determined for any month of such quarter is equal to the average of(i) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts(as defined), as reported in *The Wall Street Journal*,for such contracts which expired in each of the five months prior to suchmonth, (ii) the final settlement price per MMBtu for Henry Hub Gas FuturesContracts, as reported in *The Wall Street Journal*,for such contracts which expire during such month and (iii) the closing settlementprice per MMBtu of Henry Hub Gas Futures Contracts determined as of thecontract settlement date for such month, as reported in *The WallStreet Journal*, for such contracts which expire in each of the sixmonths following such month. A Henry Hub Gas Futures Contract is defined as agas futures contract for gas to be delivered to the Henry Hub which is tradedon the New York Mercantile Exchange.

 

Accordingly, theprice payable to the Trust for production may vary based on fluctuations innatural gas futures prices during the relevant calculation period. The pricepayable to the Trust will have a direct impact, positively or negatively, onthe quarterly distributions payable by the Trust to the Unitholders.

 

During 2003, a Coal Lessee contacted Eastern Americanand inquired as to whether it would sell the U.S. Steel Well # 26, which is awell in which the Trust owns a Net Profits Interests. The Coal Lessee statedthat the well would materially interfere with the Coal Lessee’s proposed miningoperations. Eastern American reviewed the Trust Agreement and production fromthis well to determine if it could cause the Trust to sell its Net ProfitsInterest in the well. Upon review, it was discovered that the Net ProfitsInterests associated with the U.S. Steel #26 well accounted for less than

 

23

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0.25% of the total production from the Underlying Properties for theprior twelve (12) month period. Eastern American advised the Coal Lessee thatit could sell this well. Eastern American received $11,437 for the sale of theU.S Steel Well #26. The Trust’s share of the proceeds of $10,293 was includedin the Distributable Income of the Trust during the year ended December 31,2003.

 

During 2004, an oil andgas company contacted Eastern American and inquired as to whether it would sellcertain assets situated in Centre County, Pennsylvania including the Horne #1,Horne #2 and Horne #15 wells (the Horne Underlying Properties), which are wellsin which the Trust owned a Net Profits Interests. Eastern American reviewed theTrust Agreement and certified to the Trustee that:  (i) the gross purchase price to be receivedby Eastern American for the sale of the Horne Underlying Properties in a singletransaction or a series of related transactions was less than $500,000; (ii)the Assignee of the Horne Underlying Properties was not an Affiliate of EasternAmerican; (iii) the aggregate sale proceeds of $80,205 to be received by theTrust from Eastern American (the Trust’s Horne Sale Proceeds) represented thefair value to the Trust for Net Profits Interests to be released by the Trusteein connection with Eastern American’s sale of the Horne Underlying Properties;and (iv) the Trust’s Horne Sale Proceeds plus the aggregate sale proceedsreceived by the Trust pursuant to Section 3.02(b)(ii) of the Trust Agreementwith respect to all other Net Profits Interests previously released by theTrustee pursuant to Section 3.02(b) during the most recently completed twelvecalendar months did not exceed $500,000. Eastern American advised the oil andgas company that it could sell these wells. The Trust’s share of the proceedsof $80,205 was included in the Distributable Income of the Trust during theyear ended December 31, 2004.

 

Also, during 2004, alandowner contacted Eastern American to inquire about the sale of certain wellslocated on the landowner’s property, including the Wurst #2 well, which is awell in which the Trust owns a Net Profits Interest. Eastern certified to theTrust that, (i) the Assignee of the Wurst #2 was not an Affiliate of Easternand, (ii) the aggregate sale proceeds to be received from all other sales ofwells in which the Trust owned a Net Profits Interest and previously releasedby the Trust during the preceeding twelve (12) calendar months did not exceed$500,000. The Wurst #2 well was found to be uneconomic to operate and wassubject to plugging and abandonment by Eastern American if not assigned to thelandowner. Eastern American advised the landowner that it could assign thiswell. The Wurst #2 well had no value and no cash distribution was made to theTrust.

 

Over the remaining lifeof the Trust, additional wells may need to be disposed of for similar or otherreasons.

 

The Trust isresponsible for paying the Trustee’s fees and all legal, accounting,engineering and stock exchange fees, printing costs and other administrativeexpenses incurred by or at the direction of the Trustee. The total of allTrustee fees and Trust administrative expenses for 2005 was $1,474,570including the Trustee’s fee of $108,000. In addition to such expenses, in 2005,the Trust paid Eastern American an overhead reimbursement of $317,324. Theoverhead reimbursement increases by 3.5% per year and is payable quarterly.

 

On December 8, 2004, theTrust announced approval by the Trust Unitholders of a proposal to electJPMorgan Chase to serve as successor trustee of the Trust upon the effectivedate of the resignation of The Bank of New York as trustee of and depositaryfor the Trust and to amend the Trust Agreement to change the compensation ofthe Trustee. The resignation of The Bank of New York took effect on January 1,2005. As successor trustee, JPMorgan Chase receives annual compensation of$108,000, plus fees and expenses.

 

During the last twoquarters of 2005, the Trust incurred substantially increased fees forprofessional services relating to the Ensource exchange offer mentioned on Page2. These expenses, and any other expenses, will decrease distributions to theUnitholders. Expenses relating to the Ensource exchange offer incurred by theTrust during 2005 total approximately $725,798, including $418,639 for fees andexpenses the Trust paid to a financial advisory firm in connection with itsanalysis of the Ensource exchange offer. In addition, the Trust has incurredand is likely to continue to incur additional increased legal and otherexpenses relating to the Ensource exchange offer. The aggregate amount offuture additional expenses could be substantially greater or less than the 2005expenses.

 

The costs theTrust incurs in the future will fluctuate depending primarily on the expensesthe Trust incurs for professional services, particularly legal, accounting andengineering services. If Ensource makes a substantially different offer toacquire control of the Trust, the Trust could incur substantial additional feesfor additional financial advisory services and other professional andadministrative expenses.

 

24

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**CriticalAccounting Policies**

** **

The following is asummary of the critical accounting policies followed by the Trust.

 

*Basis of Accounting:*

 

The financial statementsof the Trust differ from financial statements prepared in accordance withaccounting principles generally accepted in the United States of America due tothe following: (i) certain cash reserves may be established for contingencieswhich were not accrued in the financial statements; (ii) amortization of theNet Profits Interests in gas properties is charged directly to Trust Corpus;and (iii) the sale of the Net Profits Interests is reflected in the Statementsof Distributable Income as cash proceeds to the Trust.

 

*Net Profits Interests in GasProperties:*

 

The Net Profits Interestsin gas properties are periodically assessed to determine whether their netcapitalized cost is impaired. The Trust will determine if a writedown isnecessary to its investment in the Net Profits Interests in gas properties tothe extent that total capitalized costs, less accumulated amortization, exceedundiscounted future net revenues attributable to proved gas reserves of theUnderlying Properties. The Trust will then provide a writedown to the extentthat the net capitalized costs exceed the discounted future net revenuesattributable to proved gas reserves of the Underlying Properties. Any suchwritedown would not reduce distributable income, although it would reduce TrustCorpus.

 

Amortization of the NetProfits Interests in gas properties is calculated on a units-of-productionbasis, whereby the Trust’s cost basis in the properties is divided by totalTrust proved reserves to derive an amortization rate per reserve unit. Suchamortization does not reduce distributable income, rather it is chargeddirectly to Trust Corpus. Revisions to estimated future units-of-production aretreated on a prospective basis beginning on the date significant revisions areknown.

 

The Net Profits Interestimpairment test and the determination of amortization rates are dependent onestimates of proved gas reserves attributable to the Trust. Numerousuncertainties are inherent in estimating reserve volumes and values, includingeconomic and operating conditions, and such estimates are subject to change asadditional information becomes available.

 

*IncomeTaxes:*

 

**Tax counsel to the Trust advisedthe Trust at the time of formation that, under then current tax laws, the Trustwould be classified as a grantor trust for federal and state income taxpurposes and, therefore, would not be subject to taxation at the Trust level. TheTrust continues to be tax exempt. Accordingly, no provision for federal orstate income taxes has been made. However, the opinion of tax counsel is notbinding on taxing authorities.**

 

**New AccountingStandards**

** **

**In May 2005, the Financial Accounting StandardsBoard (FASB) issued Statement of Financial Accounting Standards No. 154 (SFAS154), “Accounting Changes and Error Corrections,” a replacement of APB OpinionNo. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes inInterim Financial Statements” in order to change the requirements for theaccounting and reporting of a change in accounting principal.  SFAS 154applies to all voluntary changed in accounting principal and changes requiredby an accounting pronouncement in the unusual instance that the pronouncementdoes not include specific transition provisions.  The Statement requiresretrospective application to prior periods’ financial statements of changes inaccounting principal, unless it is impractical to determine either the period-specificeffects or the cumulative effect of the change.  SFAS 154 becomeseffective for accounting changes and corrections of errors incurred during thefiscal years beginning after December 15, 2005.  The Trust does not expectthe adoption of SFAS 154 to have a material impact on the Trust’s financialstatements.**

 

25

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**Liquidity andCapital Resources**

** **

The Trust has no sourceof liquidity or capital resources other than the distributions received from theNet Profits Interests.

 

In accordance with theprovisions of the Conveyances, generally all revenues received by the Trust,net of Trust administrative expenses and the amount of established reserves,are distributed currently to the Unitholders.

 

The Trust did not haveany contractual obligations as of December 31, 2005. At December 31, 2005, theTrust had accounts payable of $318,120 and distributions payable of $3,933,449.

 

#### **Results ofOperations**

 

##### 2005 Compared with 2004

 

The Trust’s distributable income was $14,597,387 forthe twelve months ended December 31, 2005 as compared to $12,019,847 for thetwelve months ended December 31, 2004. This increase was due to an increase inRoyalty Income for the twelve months ended December 31, 2005 ($18,179,459) as comparedto the twelve months ended December 31, 2004 ($14,449,208). The increase inRoyalty Income was due to an increase in the average price payable to the Trustunder the Gas Purchase Contract as discussed below ($9.315 per Mcf for thetwelve months ended December 31, 2005; $6.989 per Mcf for the twelve monthsended December 31, 2004). This increase was offset by a decrease in productionof gas attributable to the Net Profits Interests for the twelve months endedDecember 31, 2005 (1,956 Mmcf) as compared to the twelve months ended December31, 2004 (2,068 Mmcf). The decline in production is primarily attributable tonatural production declines and the sale of wells. Taxes on production andproperty were $1,256,330 for the twelve months ended December 31, 2005 ascompared to $989,430 for the twelve months ended December 31, 2004. Theincrease in taxes is due directly to the increase in Royalty Income asdiscussed above. The production tax for the quarter also includes one month ofcharges related to a new West Virginia tax on the Severance of NaturalResources that is effective for gas produced after November 30, 2005. Theadditional Severance Tax rate is four and seven-tenths cents per MCF. Trustgeneral and administrative expenses were $1,791,894 for the twelve months endedDecember 31, 2005 as compared to $1,002,397 for the twelve months endedDecember 31, 2004. The increase of $789,497 in general and administrativeexpenses was due primarily to professional fees of approximately $725,798incurred as a direct result of the Ensource exchange offer as described on Page2. The distributable income includes no Cash Proceeds on Sale of Net ProfitsInterests for the period ended December 31, 2005, while $80,205 was recognizedin the corresponding prior twelve months.

 

During the twelve months ended December 31, 2005, theTrustee added an additional $885,000 to the cash reserve balance compared tothe twelve months ended December 31, 2004 in the amount of $100,000. Thisreserve was established to facilitate the payment of vendor invoices on atimely basis. The increase of this reserve reduced the Distribution Amount by$885,000 or $0.15 per unit for the twelve months ended December 31, 2005 and by$100,000 or $0.0169 per unit for the twelve months ended December 31, 2004.Amortization of Nets Profits Interests in Gas Properties was $3,321,243 for thetwelve months ended December 31, 2005 as compared to $3,818,158 for the twelvemonths ended December 31, 2004. This decrease was due to the decrease inproduction volumes and a decrease in the depletion rate to $1.6976 for thetwelve months ended December 31, 2005 from $1.8465 for the year ended December31, 2004, due to higher reserves.

 

The average price payable to the Trust for gasproduction attributable to the Net Profits Interests was $9.315 per Mcf for thetwelve months ended December 31, 2005 and $6.989 per Mcf for the twelve monthsended December 31, 2004. The price per Mcf was higher for the twelve monthsended December 31, 2005 than for the corresponding twelve month period endedDecember 31, 2004 due to an increase in the average spot market price for gasdelivered at the Henry Hub near Henry, Louisiana ($8.168 per Dth for the twelvemonths ended December 31, 2005; $6.054 per Dth for the twelve months ended December31, 2004).

 

##### 2004 Compared with 2003

 

The Trust’s distributable income was $12,019,847 forthe twelve months ended December 31, 2004 as compared to $10,947,816 for thetwelve months ended December 31, 2003. This increase was due to an increase inRoyalty Income for the twelve months ended December 31, 2004 ($14,449,208) ascompared to the twelve months ended December 31,

 

26

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2004 ($14,449,208)as compared to the twelve months ended December 31, 2003 ($13,177,510). Theincrease in Royalty Income was due to an increase in the average price payableto the Trust under the Gas Purchase Contract as discussed below ($6.989 per Mcffor the twelve months ended December 31, 2004; $6.086 per Mcf for the twelvemonths ended December 31, 2003). This increase was offset by a decrease inproduction of gas attributable to the Net Profits Interests for the twelvemonths ended December 31, 2004 (2,068 Mmcf) as compared to the twelve monthsended December 31, 2003 (2,161 Mmcf). The decline in production is primarilyattributable to natural production declines and the sale of wells. Taxes onproduction and property were $989,430 for the twelve months ended December 31,2004 as compared to $897,881 for the twelve months ended December 31, 2003. Theincrease in taxes is due directly to the increase in Royalty Income asdiscussed above. Trust general and administrative expenses were $1,002,397 forthe twelve months ended December 31, 2004 as compared to $833,027 for thetwelve months ended December 31, 2003. The increase in general andadministrative expenses was due primarily to an increase in legal fees of$64,234 and $51,406 in direct expenses related to the resignation of the formertrustee and the appointment of a successor trustee. The distributable incomeincludes Cash Proceeds on Sale of Net Profits Interests of $80,205 for theperiod ended December 31, 2004, while $10,293 was recognized in thecorresponding prior twelve months.

 

During the twelve months ended December 31, 2004, theTrustee added an additional $100,000 to the cash reserve balance which wasestablished during the twelve months ended December 31, 2003 in the amount of$215,000. This reserve was established to facilitate the payment of vendorinvoices on a timely basis. The establishment and subsequent increase of thisreserve reduced the Distribution Amount by $100,000 or $0.0169 per unit for thetwelve months ended December 31, 2004 and by $215,000 or $0.0365 per unit forthe twelve months ended December 31, 2003. Amortization of Nets ProfitsInterests in Gas Properties was $3,818,158 for the twelve months ended December31, 2004 as compared to $4,053,133 for the twelve months ended December 31,2003. This decrease was primarily due to the decrease in production volumes.

 

The average price payableto the Trust for gas production attributable to the Net Profits Interests was$6.989 per Mcf for the twelve months ended December 31, 2004 and $6.086 per Mcffor the twelve months ended December 31, 2003. The price per Mcf was higher forthe twelve months ended December 31, 2004 than for the corresponding twelvemonth period ended December 31, 2003 due to an increase in the average spotmarket price for gas delivered at the Henry Hub near Henry, Louisiana ($6.054per Dth for the twelve months ended December 31, 2004; $5.233 per Dth for thetwelve months ended December 31, 2003).

 

**Off-Balance SheetArrangements**

** **

The Trust does not have any off-balance sheet arrangements that have orare reasonably likely to have a current or future effect on the Trust’sfinancial condition, changes in financial condition, revenue or expenses,results of operations, liquidity, capital expenditures or capital resourcesthat is material to investors.

 

**Item 7A.   *Quantitative and Qualitative Disclosure About Market Risk***

 

The Trust does not engagein any operations and does not utilize market risk sensitive instruments,either for trading purposes or for other than trading purposes. As described indetail elsewhere herein, the Depositary Units consist of beneficial ownershipof one unit of beneficial interest in the Trust and a $20 face amountbeneficial ownership interest in a $1,000 face amount zero coupon TreasuryObligation maturing on May 15, 2013. High and low price information for theTreasury Obligations is included under Item 5. As described in detail elsewhereherein, gas production attributable to the Net Profits Interest is sold to awholly owned subsidiary of Eastern American pursuant to the Gas PurchaseContract described herein.

 

**Item 8.****    *Financial Statements and Supplementary Data.***

 
| Financial Statements                                                                        |   |
|---------------------------------------------------------------------------------------------|--------|
| Report of Independent Registered Public Accounting  Firm                                    |   |
| Statements  of Assets, Liabilities and Trust Corpus as of December 31, 2005 and 2004        |   |
| Statements of  Distributable Income for the years ended December 31, 2005, 2004 and 2003    |   |
| Statements of  Changes in Trust Corpus for the years ended December 31, 2005, 2004 and 2003 |   |
| Notes to Financial  Statements                                                              |   |

 

27

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**Item 9.*****           Changes in andDisagreements with Accountants on Accounting and Financial Disclosure.***

 

None.

 

**Item9A.  *Controls and Procedures***

 

**Evaluationof Disclosure Controls and Procedures**

 

The 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, processed, summarizedand reported within the time periods specified in the SEC’s rules andregulations.  Disclosure controls and procedures include controls andprocedures designed to ensure that information required to be disclosed by theTrust is accumulated and communicated by several parties, including withoutlimitation, the working interest owner, Eastern American Energy Corporation (“EasternAmerican”), and the independent reserve engineer to JPMorgan Chase Bank, N.A.,as Trustee of the Trust, and its employees who participate in the preparationof the Trust’s periodic reports as appropriate to allow timely decisionsregarding required disclosure.  In addition, the Trustee is required bythe Trust Agreement to engage and has engaged an independent registered publicaccounting firm to review the quarterly financial statements of the Trust andaudit the annual financial statements of the Trust, which includes financialdata provided by Eastern American.

 

As of December 31,2005, the Trustee carried out an evaluation of the Trustee’s disclosurecontrols and procedures. Mike Ulrich, as Trust Officer of the Trustee, hasconcluded that the disclosure controls and procedures are effective.

 

Due to the contractualarrangements of (i) the Trust Agreement and (ii) the rights of the Trusteeunder the Conveyances regarding information furnished by Eastern American, thereare certain potential weaknesses that may limit the effectiveness of disclosurecontrols and procedures established by the Trustee or its employees and theirability to verify the accuracy of certain financial information.  The contractual limitations creatingpotential weaknesses in disclosure controls and procedures may be deemed toinclude:

 

•Eastern American and its consolidatedsubsidiaries manage information relating to the Trust, including (i) historicaloperating data, including production volumes, marketing of products, operatingand capital expenditures, environmental and other liabilities, the effects ofregulatory changes and the number of producing wells and acreage, (ii) plansfor future operating and capital expenditures and (iii) geological datarelating to reserves; and

 

•The independent reserve engineer, asan expert with respect to the annual reserve report, which includes projectedproduction, operating expenses and capital expenses.

 

Other than reviewing thefinancial and other information provided to the Trust by Eastern American andthe independent reserve engineer, the Trustee made no independent or directverification of this financial or other information.

 

28

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The Trustee does notintend to expand its responsibilities beyond those permitted or required by theTrust Agreement and those required under applicable law.

 

The Trustee does notexpect that the Trustee’s disclosure controls and procedures or the Trustee’sinternal control over financial reporting will prevent all errors and allfraud.  Further, the design of disclosurecontrols and procedures and internal control over financial reporting mustreflect the fact that there are resource constraints, and the benefits ofcontrols must be considered relative to their costs.  Because of the inherent limitations in allcontrol systems, no evaluation of controls can provide absolute assurance thatall control issues and instances of fraud, if any, have been detected.

 

**Changesin Internal Control Over Financial Reporting**

 

In connection with theevaluation by the Trustee of changes in internal control over financialreporting of the Trust that occurred during the Trust’s last fiscal quarter, nochange in the Trust’s internal control over financial reporting was identifiedthat has materially affected, or is reasonably likely to materially affect, theTrust’s internal control over financial reporting.

 

**Trustee’sReport on Internal Control over Financial Reporting**

 

The Trustee isresponsible for establishing and maintaining adequate internal control overfinancial reporting, as such term is defined in Rule 13a-15(f) promulgatedunder the Securities and Exchange Act of 1934, as amended. The Trusteeconducted an evaluation of the effectiveness of the Trust’s internal controlover financial reporting based on the criteria established in *Internal Control-Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission.Based on the Trustee’s evaluation under the framework in *Internal Control-Integrated Framework*, theTrustee concluded that the Trust’s internal control over financial reportingwas effective as of December 31, 2005. The Trustee’s assessment of theeffectiveness of the Trust’s internal control over financial reporting as ofDecember 31, 2005 has been audited by PricewaterhouseCoopers LLP, anindependent registered public accounting firm, as stated in their report whichis included herein.

 

A registrant’s internalcontrol over financial reporting is a process designed to provide reasonableassurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generallyaccepted accounting principles. A registrant’s internal control over financialreporting includes those policies and procedures that (i) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the registrant; (ii)provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generallyaccepted accounting principles, and that receipts and expenditures of theregistrant are being made only in accordance with authorizations of managementand directors of the registrant; and (iii) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or dispositionof the registrant s assets that could have a material effect on the financialstatements.

 

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements. Also, projections of any evaluation of effectiveness tofuture periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.

 

**Item9B.  *OtherInformation.***

 

None.

 

**PARTIII**

** **

**Item 10.   *Directors and ExecutiveOfficers of the Registrant.***

 

The Trust has nodirectors or executive officers. The Trustee is a corporate trustee which maybe removed by the affirmative vote of holders of a majority of the Trust Unitsthen outstanding at a meeting of the Unitholders of the Trust at which a quorumis present. The Trust is not required to and does not hold annual meetings ofthe Unitholders.

 

29

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The Trust alsodoes not have an audit committee or body serving a similar function, and doesnot have an “audit committee financial expert”. The Trust has not adopted acode of ethics, as the Trust has no directors, officers, or employees. TheTrust has not adopted a process by which Unitholders may communicate with boardmembers, as the Trust has no board members or persons fulfilling a similarfunction. Unitholders may contact the Trustee at the following address:  JPMorgan Chase Bank, N.A., Trustee of EasternAmerican Natural Gas Trust, Institutional Trust Services, 700 Lavaca, Austin, Texas 78701.

 

**Item 11.   *Executive Compensation.***

 

The Trust has noofficers or directors, and is administered by the Trustee. For the year endedDecember 31, 2005, JPMorgan Chase Bank, N.A., as Trustee received $108,000 andfor the years ended December 31, 2004 and 2003, The Bank of New York as Trusteereceived $45,000 annually, as Trustee fees and $1,474,570, $650,805 and$491,803, respectively, as reimbursement of legal, accounting, and otherprofessional expenses for such services. Effective January 1, 2005, the annualTrustee fee was fixed at $108,000.

 

**Item 12.   *Security Ownership ofCertain Beneficial Owners and Management.***

 

(a)                                  SecurityOwnership of Certain Beneficial Owners.

 

Basedon filings with the Securities and Exchange Commission, the Trust is not awareof any person owning beneficially more than five percent of the Units as ofMarch 1, 2006.

 

(b)                                 SecurityOwnership of Management.

 

Not applicable.

 

(c)                                  Changesin Control.

 

Exceptas described below, the Trust knows of no arrangements, including the pledge ofsecurities of the Trust, the operation of which may at a subsequent date resultin a change in control of the Trust. As described elsewhere herein and in moredetail in the Trust’s Schedule 14-D-9, Ensource Energy Income Fund LP, a newlyformed Delaware limited partnership, has commenced an unsolicited exchangeoffer seeking control of the Trust.

 

(d)                                 Securitiesauthorized for issuance under equity compensation plans.

 

The Trust has no equitycompensation plans.

 

**Item 13.   *Certain Relationships andRelated Transactions.***

 

None.

 

**Item 14.   *Principal Accounting Feesand Services***

 

**AuditFees**

 

The fees, includingexpenses, PricewaterhouseCoopers LLP billed the Trust for each of the last twofiscal years for professional services rendered in connection with the auditsof the Trust’s annual financial statements and review of the Trust quarterlyinterim financial statements were $185,250 in 2005 and $212,355 in 2004.

 

**Audit-RelatedFees**

 

PricewaterhouseCoopersLLP did not bill the Trust any additional fees in the last two fiscal years forassurance and related services that are reasonably related to the performanceof the audit or review of the Trust’s financial statements.

 

30

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**Tax Fees**

 

The fees, includingexpenses, PricewaterhouseCoopers LLP billed the Trust for each of the last twofiscal years for compliance, tax advice, or planning were $123,715 in 2005 and$126,484 in 2004.

 

**AllOther Fees**

 

PricewaterhouseCoopersLLP did not bill the Trust any additional fees in the last two fiscal years forproducts and services provided by PricewaterhouseCoopers LLP, other thanservices reported above.

 

**Pre-ApprovalPolicies**

 

The Trust does not havean audit committee or body performing a similar function. Pre-approval of allservices performed by PricewaterhouseCoopers LLP and approval of the relatedfees is granted by the Trustee.

 

PART IV

 

**Item 15.****         *Exhibits,Financial Statement Schedules.***

 
| Reports                                                                                                      |   |
|--------------------------------------------------------------------------------------------------------------|--------|
| Reserve  Report of Ryder Scott Company, Independent Petroleum Engineers                                      |   |
|                                                                                                         |   |
| Financial Statements                                                                                         |   |
|                                                                                                         |   |
| The following financial  statements are included in this Annual Report on Form 10-K on the pages  indicated: |   |
| Report of Independent Registered Public Accounting  Firm                                                     |   |
| Statements  of Assets, Liabilities and Trust Corpus as of December 31, 2005 and 2004                         |   |
| Statements of  Distributable Income for the years ended December 31, 2005, 2004 and 2003                     |   |
| Statements of  Changes in Trust Corpus for the years ended December 31, 2005, 2004 and 2003                  |   |
| Notes to Financial  Statements                                                                               |   |

 

Schedules

 

All schedules have beenomitted because they are not required, not applicable or the informationrequired has been included elsewhere herein.

 

Exhibits

 

Except as otherwiseindicated below, all exhibits, except Exhibit 31 and Exhibit 32, areincorporated herein by reference to the indicated exhibits to filingspreviously made by the registrant with the Securities and Exchange Commission. Allreferences are to the registrant’s Registration Statement on Form S-1,Registration No. 33-56336, except for Exhibit 3.1, which is incorporated byreference to the Registrant’s Annual Report on Form 10-K for the year endedDecember 31, 1994.

 
| **Exhibit  Number** | ** ** | ** ** |
|---------------------|------------|------------|
| 3.1                 |       |       | Second  Amended and Restated Trust Agreement of Eastern American Natural Gas Trust |
|                |       |       |   |
| 4.1                 |       |       | Specimen Depositary  Receipt |
| 4.2                 |       |       | Form of NPI Royalty  Deposit Agreement |
| 10.1                |       |       | Form of Conveyance |
| 10.2                |       |       | Form of Term NPI  Conveyance |
| 10.3                |       |       | Form of Gas Purchase  Contract between Eastern American Energy Corporation, Eastern American  Marketing Corporation and Eastern American Natural Gas Trust |
| 10.4                |       |       | Form of Conveyance of  Production Payment/Assignment of Production from Eastern American Natural Gas  Trust to Eastern American Marketing Corporation |
| 10.5                |       |       | Form of Assignment and  Standby Performance Agreement |
| 31        |       |       | Rule  13a-14(a)/15d-14(a) Certifications |
| 32        |       |       | Section 1350  Certifications |

 

31

----

 

**SIGNATURES**

 

**Pursuantto the requirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized on this 16th day of March, 2006.**

 
|   | EASTERN AMERICAN  NATURAL GAS TRUST |
|--------|-------------------------------------|
|   |                                |
|   | By:                                 | JPMorgan Chase Bank,  N.A., Trustee |
|   |                                |
|   | By:                                 | /s/ Mike Ulrich |   |
|   | Name:                               | Mike Ulrich |
|   | Title:                              | Vice President |

 

The Registrant, EasternAmerican Natural Gas Trust, has no principal executive officer, principalfinancial officer, controller or principal accounting officer, board ofdirectors or persons performing similar functions. Accordingly, no additionalsignatures are available and none have been provided.

 

32

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[Ryder ScottCompany, Independent Petroleum Engineers Letterhead]

 

January 12, 2006

 

Eastern American NaturalGas Trust

J P Morgan Chase Bank,N.A., Trustee

Institutional TrustServices

700 Lavaca, 2ndFloor

Austin, Texas 78701

 

Gentlemen:

 

Pursuant to your request,we present below estimates of the net proved reserves attributable to theinterests of the Eastern American Natural Gas Trust (Trust) as of December 31,2005. The Trust is a grantor trust formed to hold interests in certain domesticoil and gas properties owned by Eastern American Energy Corporation (EAEC), awholly owned subsidiary of Energy Corporation of America (ECA). The interestsconveyed to the Trust consist of a net profits interest derived from workingand royalty interests in numerous properties. The Net Profits Interest consistsof (1) a life-of-properties interest (“Royalty NPI”) and (2) a term interest (“TermNPI”). The properties included in the Trust are located in the states ofPennsylvania and West Virginia.

 

The estimated reserve quantities and future incomequantities presented in this report are related to a large extent tohydrocarbon prices. Hydrocarbon prices in effect at December 31, 2005 were usedin the preparation of this report as required by Securities and Exchange Commission(SEC) and Financial Accounting Standards Bulletin No. 69 (FASB 69) guidelines;however, actual future prices may vary significantly from December 31, 2005prices for reasons discussed in more detail in other sections of this report. Therefore,quantities of reserves actually recovered and quantities of income actuallyreceived may differ significantly from the estimated quantities presented inthis report.

 
| ** **           | ** ** | **As of December 31, 2005** | ** ** | ** **                              | ** ** |
|----------------------|------------|-----------------------------|------------|-----------------------------------------|------------|
| ** **           | ** ** | **Gas**                     | ** ** | **Estimated  Future Net  Cash Inflows** | ** ** | **Present  Value  At 10%** | ** ** |
| ** **           | ** ** | **(MMCF)**                  | ** ** | **(M$)**                                | ** ** | **(M$)** | ** ** |
| Proved Net Developed |       |                        |       |                                    |       |   |   |
|                 |       |                        |       |                                    |       |   |   |
| Royalty NPI          |       | 11,266                      |       | 141,923                                 |       | 59,278 |   |
| Term NPI             |       | 5,997                       |       | 75,540                                  |       | 54,992 |   |
| Total                |       | 17,263                      |       | 217,463                                 |       | 114,270 |   |

 

Reserve quantities arecalculated differently for a Net Profits Interest because such interests do notentitle the Trust to a specific quantity of oil or gas but to 90 percent of theNet Proceeds derived therefrom beginning on January 1, 2006 for natural gas. Accordingly,there is no precise method of allocating estimates of the quantities of provedreserves attributable to the Net Profits Interest between the interest held bythe Trust and the interests to be retained by EAEC. For purposes of thispresentation, the proved reserves attributable to the Net Profits Interestshave been proportionately reduced to reflect the future estimated costs andexpenses deducted in the calculation of Net Proceeds with respect to the NetProfits Interests. Accordingly, the reserves presented for the Net ProfitsInterest reflect quantities of gas that are free of future costs or expensesbased on the price and cost assumptions utilized in this report. The allocationof proved reserves of the Net Profits Interest between the Trust and EAEC willvary in the future as relative estimates of future gross revenues and futurenet incomes vary. Furthermore, EAEC requested that for purposes of our reportthe “Royalty NPI” be calculated beyond the Liquidation Date of May 15, 2013,even though by the terms of the Trust Agreement the Royalty NPI will be sold bythe Trustee on or about this date and a liquidating distribution of the salesproceeds from such sale would be made to holders of Trust Units. The TrustAgreement provides that the “Term NPI” entitles the Trust to receive the netproceeds from the gas produced

 

A-1

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from the propertiesburdened by the “Term NPI” until the earlier of May 15, 2013 or until such timeas 41,683 MMCF of gas has been produced. For purposes of this report, the “TermNPI” was limited to May 15, 2013.

 

All gas volumes are salesgas expressed in MMCF at the pressure and temperature bases of the area wherethe gas reserves are located. The estimated future net cash inflows aredescribed later in this report.

 

The proved reserves presentedin this report comply with the Securities and Exchange Commission’s RegulationS-X Part 210.4-10 Sec. (a) as clarified by subsequent Commission StaffAccounting Bulletins, and are based on the following definitions and criteria:

 

Proved reservesof crude oil, natural gas, or natural gas liquids are estimated quantities thatgeological and engineering data demonstrate with reasonable certainty to berecoverable in the future from known reservoirs under existing conditions. Reservoirsare considered proved if economic producibility is supported by actualproduction or formation tests. In certain instances, proved reserves may beassigned on the basis of a combination of core analysis and electrical andother type logs which indicate the reservoirs are analogous to reservoirs inthe same field which are producing or have demonstrated the ability to produceon a formation test. The area of a reservoir considered proved includes (1)that portion delineated by drilling and defined by fluid contacts, if any, and(2) the adjoining portions not yet drilled that can be reasonably judged aseconomically productive on the basis of available geological and engineeringdata. In the absence of data on fluid contacts, the lowest known structuraloccurrence of hydrocarbons controls the lower proved limit of the reservoir. Provedreserves are estimates of hydrocarbons to be recovered from a given dateforward. They may be revised as hydrocarbons are produced and additional databecomes available. Proved natural gas reserves consist of non-associated,associated and dissolved gas. An appropriate reduction in gas reserves has beenmade for the expected removal of natural gas liquids, for lease and plant fuel,and for the exclusion of non-hydrocarbon gases if they occur in significantquantities.

 

Reserves that can beproduced economically through the application of improved recovery techniquesare included in the proved classification when these qualifications aremet:  (1) successful testing by a pilotproject or the operation of an installed program in the reservoir providessupport for the engineering analysis on which the project or program was based,and (2) it is reasonably certain the project will proceed. Improved recoveryincludes all methods for supplementing natural reservoir forces and energy, orotherwise increasing ultimate recovery from a reservoir, including (1) pressuremaintenance, (2) cycling, and (3) secondary recovery in its original sense. Improvedrecovery also includes the enhanced recovery methods of thermal, chemicalflooding, and the use of miscible and immiscible displacement fluids.

 

Estimates of provedreserves do not include crude oil, natural gas, or natural gas liquids beingheld in underground or surface storage.

 

(i) “developed reserves”which are those proved reserves reasonably expected to be recovered throughexisting wells with existing equipment and operating methods, including (a) “developedproducing reserves” which are those proved developed reserves reasonablyexpected to be produced from existing completion intervals now open forproduction in existing wells, and (b) “developed non-producing reserves” whichare those proved developed reserves which exist behind the casing of existingwells which are reasonably expected to be produced through these wells in thepredictable future where the cost of making such hydrocarbons available forproduction should be relatively small compared to the cost of a new well; and

 

(ii) “undevelopedreserves” which are those proved reserves reasonably expected to be recoveredfrom new wells on undrilled acreage, from existing wells where a relativelylarge expenditure is required and from acreage for which an application offluid injection or other improved recovery technique is contemplated where thetechnique has been proved effective by actual tests in the area in the samereservoir. Reserves from undrilled acreage are limited to those drilling unitsoffsetting productive units that are reasonably certain of production whendrilled. Proved reserves for other undrilled units are included only where itcan be demonstrated with reasonable certainty that there is continuity ofproduction from the existing productive formation.

 

A-2

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In accordance with therequirements of FASB 69, estimates of future cash inflows, future costs andfuture net cash inflows before income tax, as well as estimated reservequantities, as of December 31, 2005 from this report are presented in thefollowing table:

 
| ** **                                      | ** ** | **As of December 31, 2005** | ** ** |
|-------------------------------------------------|------------|-----------------------------|------------|
| ** **                                      | ** ** | **Royalty  NPI**            | ** ** | **Term  NPI** | ** ** | **Totals** | ** ** |
| Total Proved                                    |       |                        |       |   |   |   |   |
| Future Cash  Inflows (M$)                       |       | 141,923                     |       | 75,540 |   | 217,463 |   |
| Future Costs                                    |       |                        |       |   |   |   |   |
| Production (M$)                                 |       | 0                           |       | 0 |   | 0 |   |
| Development (M$)                                |       | 0                           |       | 0 |   | 0 |   |
| Total Costs (M$)                                |       | 0                           |       | 0 |   | 0 |   |
|                                            |       |                        |       |   |   |   |   |
| Future Net Cash  Inflows Before Income Tax (M$) |       | 141,923                     |       | 75,540 |   | 217,463 |   |
|                                            |       |                        |       |   |   |   |   |
| Present Value at 10% Before Income Tax (M$)     |       | 59,278                      |       | 54,992 |   | 114,270 |   |

 
| ** **                      | ** ** | **As of December 31, 2005** | ** ** |
|---------------------------------|------------|-----------------------------|------------|
| ** **                      | ** ** | **Royalty  NPI**            | ** ** | **Term  NPI** | ** ** | **Totals** | ** ** |
| Proved Net Developed Reserves   |       |                        |       |   |   |   |   |
| Gas (MMCF)                      |       | 11,266                      |       | 5,997 |   | 17,263 |   |
|                            |       |                        |       |   |   |   |   |
| Proved Net Undeveloped Reserves |       |                        |       |   |   |   |   |
| Gas (MMCF)                      |       | 0                           |       | 0 |   | 0 |   |
|                            |       |                        |       |   |   |   |   |
| Total Proved Net Reserves       |       |                        |       |   |   |   |   |
| Gas (MMCF)                      |       | 11,266                      |       | 5,997 |   | 17,263 |   |

 

For Net Profits Interest,the future cash inflows are, as described previously, after consideration offuture costs or expenses based on the price and cost assumptions utilized inthis report. Therefore, the future cash inflows are the same as the future netcash inflows. The effects of depreciation, depletion and federal income taxeshave not been taken into account in estimating future net cash inflows.

 

EAEC furnished us gasprices in effect at December 31, 2005 and with its forecasts of future gasprices which take into account Securities and Exchange Commission guidelines,current market prices, contract prices and fixed and determinable priceescalations where applicable. In accordance with Securities and ExchangeCommission guidelines, the future gas prices used in this report make noallowances for future gas price increases or decreases which may occur as aresult of inflation nor do they account for seasonal variations in gas priceswhich are likely to cause future yearly average gas prices to be somewhathigher than December gas prices. In those cases where contract market-out hasoccurred, the current market price was held constant to depletion of thereserves. In those cases where market-out has not occurred, contract gas pricesincluding fixed and determinable escalations, exclusive of inflation adjustments,were used until the contract expired and then reduced to the current marketprice for similar gas in the area and held at this reduced price to depletionof the reserves.

 

This report utilized theterms of the gas contract between Eastern Marketing Corporation (a wholly ownedsubsidiary of EAEC) and the Trust. Gas price is to be determined by a weightedprice consisting of two components during a primary term defined to begin onJanuary 1, 1993 and end December 31, 1999. The first component is the “Fixed”price which has been defined as $2.66 per Mcf beginning January 1, 1993. Thisprice escalates 5 percent per year on January 1 of each year during the primaryterm beginning in 1994. The second component is the “Variable” price which forany quarter is equal to the Henry Hub Average Spot Price (as defined) perMMBtu, plus $0.30 per MMBtu, multiplied by 110 percent to effect a Btuadjustment. The Henry Hub Average Spot Price is defined as the price per MMBtudetermined for any calendar quarter as the average price of the three months insuch quarter where each month’s price is equal to the average of (i) the

 

A-3

----

 

final settlement prices per MMBtu for Henry Hub Gas Futures Contracts(as defined), as reported in the Wall Street Journal, for such contractswhich expired in each of the five months prior to each month of such quarter,(ii) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts,as reported in the Wall Street Journal, for such contracts which expireduring such month and (iii) the closing settlement prices per MMBtu of HenryHub Gas Futures Contracts for such month, as reported in the Wall StreetJournal, for such contracts which expire in each of the six monthsfollowing such month. A Henry Hub Gas Futures Contract is defined as a gasfutures contract for gas to be delivered to the Henry Hub which is traded onthe New York Mercantile Exchange. The weighted average price is determined bygiving the “Fixed” price a 66 2/3 percent weighting and the variable price a 331/3 percent weighting.

 

Since the primary term iscomplete, the purchase price under the gas contract will be equal to the “Variable”price. EAEC computed the “Variable” price under the gas contract as of December31, 2005 as $12.597 per Mcf, utilizing $11.152 as the Henry Hub Average SpotPrice computed in accordance with the gas contract.

 

Operating costs for theleases and wells in this report were supplied by EAEC and include only costsdefined as applicable under terms of the Trust. The current operating costswere held constant throughout the life of the properties. This study does notconsider the salvage value of the lease equipment or the abandonment cost.

 

No deduction was made forindirect costs such as general administration and overhead expenses, loanrepayments, interest expenses, and exploration and development prepayments. Noattempt has been made to quantify or otherwise account for any accumulated gasproduction imbalances that may exist.

 

Our reserve estimates arebased upon a study of the properties in which the Trust has interests; however,we have not made any field examination of the properties. No consideration wasgiven in this report to potential environmental liabilities which may exist norwere any costs included for potential liability to restore and clean updamages, in any, caused by past operating practices. EAEC informed us that ithas furnished us all of the accounts, records, geological and engineering dataand reports and other data as were required for our investigation. Theownership interests, terms of the Trust, prices, taxes, and other factual datafurnished to us in connection with our investigation were accepted asrepresented. The estimates presented in this report are based on data availablethrough September, 2005.

 

At the time of formationof the Trust, EAEC assigned The Trust an interest in 65 undeveloped locations. Duringthe period 1993 through 1998, EAEC has completed it’s drilling obligation. Atotal of 59 wells were drilled over this period. Two wells were not drilled dueto title failure and four wells were not drilled due to short spacing. Reservesand projections of future production are included for the four locations whichwere not drilled due to short spacing.

 

The reserves included inthis report are estimates only and should not be construed as being exactquantities. They may or may not be actually recovered. Moreover, estimates ofproved reserves may increase or decrease as a result of future operations ofEAEC. Moreover, due to the nature of the Net Profits Interest, a change in thefuture costs, or prices different from those projected herein may result in achange in the computed reserves and the Net Proceeds to the Trust even if thereare no revisions or additions to the gross reserves attributed to the property.

 

The future productionrates from properties now on production may be more or less than estimatedbecause of changes in market demand or allowables set by regulatory bodies. Propertieswhich are not currently producing may start producing earlier or later thananticipated in our estimates of their future production rates.

 

The future pricesreceived by EAEC for the sale of its production may be higher or lower than theprices used in this report as described above, and the operating costs andother costs relating to such production may also increase or decrease fromexisting levels; however, such possible changes in prices and costs were, inaccordance with rules adopted by the Securities and Exchange Commission,omitted from consideration in preparing this report.

 

At the request ofEAEC, we have included the following table which summarizes the total netreserves estimates from combined interest of EAEC and the Trust in theUnderlying Properties:

 

A-4

----

 

Estimated NetReserve Data

Certain CombinedLeasehold Interests of

Eastern AmericaEnergy Corporation

And The Trust

As of December 31,2005

SEC Parameters

 
| ** **             | ** ** | **Proved**    | ** ** | **Total**       | ** ** |
|------------------------|------------|---------------|------------|-----------------|------------|
| ** **             | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Proved** | ** ** |
| Net Remaining Reserves |       |          |       |            |       |   |   |
|                   |       |          |       |            |       |   |   |
| Gas-MMCF               |       | 34,653        |       | 0               |       | 34,653 |   |

 

The estimated future netincome associated with the foregoing volumes and the 10 percent discountedestimated future net income was $382,226,375 and $154,236,468, respectively. Thisevaluation utilizes the same price and cost assumptions that were utilized forevaluating the Trust and discussed earlier in the letter. The properties whichare included in the “Term NPI” were allowed to run for their full economic lifein this evaluation.

 

Neither Ryder ScottCompany nor any of its employees has any interest in the subject properties andneither the employment to make this study nor the compensation is contingent onour estimates of reserves and future cash inflows for the subject properties.

 

Very truly yours,

 

RYDER SCOTT COMPANY, L.P.

 

 

Larry T. Nelms P. E.

Managing Senior VicePresident

 

LTN:ph

 

A-5

----

 

EASTERN AMERICANNATURAL GAS TRUST

 

----

 

FINANCIALSTATEMENTS

 

as of December 31,2005 and 2004

and for the yearsended

December 31, 2005,2004 and 2003

 

----

 

Report of IndependentRegistered Public Accounting Firm

 

Tothe Unit Holders of Eastern American Natural Gas Trust and JP Morgan ChaseBank, N.A., Trustee:

 

We have completed integratedaudits of Eastern American Natural Gas Trust’s 2005 and 2004 financialstatements and of its internal control over financial reporting as of December31, 2005, and an audit of its 2003 financial statements in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, arepresented below.

 

Financialstatements

 

Wehave audited the accompanying statements of assets, liabilities and trustcorpus of Eastern American Natural Gas Trust (the “Trust”) as ofDecember 31, 2005 and 2004, and the related statements of distributableincome, and changes in trust corpus for each of the three years in the periodended December 31, 2005.  These financial statements are theresponsibility of the Trustee.  Our responsibility is to express anopinion on these financial statements based on our audits.

 

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States).  Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements.  An audit also includes assessing the accountingprinciples used and significant estimates made by the Trustee, as well asevaluating the overall financial statement presentation.  We believe thatour audits provide a reasonable basis for our opinion.

 

Asdescribed in Note 2, these financial statements were prepared on the basis ofaccounting prescribed by the Trust Agreement, which is a comprehensive basis ofaccounting other than accounting principles generally accepted in the UnitedStates of America.

 

Inour opinion, the financial statements referred to above present fairly, in allmaterial respects, the financial position of the Trust at December 31,2005 and 2004, and the distributable income and changes in trust corpus foreach of the three years in the period ended December 31, 2005, on thebasis of accounting described in Note 2.

 

F-2

----

 

Internalcontrol over financial reporting

 

Also,in our opinion, the Trustee’s assessment, included in the Trustee’s Report onInternal Control over Financial Reporting appearing under Item 9A, that theTrust maintained effective internal control over financial reporting as ofDecember 31, 2005basedon criteria established in *Internal Control -Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO), is fairly stated, in allmaterial respects, based on those criteria. Furthermore, in our opinion, theTrust maintained, in all material respects, effective internal control over financialreporting as of December 31, 2005, based on criteria established in *Internal Control - Integrated Framework* issued by the COSO.The Trustee is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting. Our responsibility is to express opinions onthe Trustee’s assessment and on the effectiveness of the Trust’s internalcontrol over financial reporting based on our audit. We conducted our audit ofinternal control over financial reporting in accordance with the standards ofthe Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether effective internal control over financial reporting was maintained inall material respects. An audit of internal control over financial reportingincludes obtaining an understanding of internal control over financialreporting, evaluating the Trustee’s assessment, testing and evaluating thedesign and operating effectiveness of internal control, and performing suchother procedures as we consider necessary in the circumstances. We believe thatour audit provides a reasonable basis for our opinions.

 

Atrust’s internal control over financial reporting is a process designed toprovide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles. A trust’s internal control overfinancial reporting includes those policies and procedures that(i) pertain to the maintenance of records that, in reasonable detail,accurately and fairly reflect the transactions and dispositions of the assetsof the trust; (ii) provide reasonable assurance that transactions arerecorded as necessary to permit preparation of financial statements inaccordance with generally accepted accounting principles, and that receipts andexpenditures of the trust are being made only in accordance with authorizationsof the trustee; and (iii) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or dispositionof the trust’s assets that could have a material effect on the financialstatements.

 

Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

 

PricewaterhouseCoopersLLP

Pittsburgh, Pennsylvania

March 16, 2006

 

F-3

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**EASTERN AMERICAN NATURAL GASTRUST**

**STATEMENTS OF ASSETS, LIABILITIES ANDTRUST CORPUS**

**as ofDecember 31, 2005 and 2004**

 
| ** **                                                      | ** ** | **2005**    | ** ** | **2004**    | ** ** |
|-----------------------------------------------------------------|------------|-------------|------------|-------------|------------|
|                                                            |       |        |       |        |       |
| Assets:                                                         |       |        |       |        |       |
|                                                            |       |        |       |        |       |
| Cash                                                            |       | $           | 43,478     |        | $          | 185,752 |   |
| Net Proceeds Receivable                                         |       | 5,408,091   |       | 3,989,827   |       |
| Net Profits Interests in Gas Properties                         |       | 93,162,180  |       | 93,162,180  |       |
| Accumulated Amortization                                        |       | (65,658,915 | )          | (62,337,672 | )          |
|                                                            |       |        |       |        |       |
| Total Assets                                                    |       | $           | 32,954,834 |        | $          | 35,000,087 |   |
|                                                            |       |        |       |        |       |
| Liabilities and Trust Corpus:                                   |       |        |       |        |       |
|                                                            |       |        |       |        |       |
| Trust General and Administrative Expenses Payable               |       | $           | 318,120    |        | $          | 220,596 |   |
| Distributions Payable                                           |       | 3,933,449   |       | 3,639,983   |       |
| Trust Corpus (5,900,000 Trust Units authorized and outstanding) |       | 28,703,265  |       | 31,139,508  |       |
|                                                            |       |        |       |        |       |
| Total Liabilities and Trust Corpus                              |       | $           | 32,954,834 |        | $          | 35,000,087 |   |

 

**Theaccompanying notes are an integral part of these financial statements.**

 

F-4

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**STATEMENTS OF DISTRIBUTABLEINCOME**

**for the years ended**

**December 31, 2005, 2004 and 2003**

 
| ** **                                                                  | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|-----------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
|                                                                        |       |       |       |       |       |       |       |
| Royalty Income                                                              |       | $          | 18,179,459 |       | $          | 14,449,208 |       | $ | 13,177,510 |   |
|                                                                        |       |       |       |       |       |       |       |
| Operating Expenses:                                                         |       |       |       |       |       |       |       |
| Taxes on production and property                                            |       | 1,256,330  |       | 989,430    |       | 897,881    |       |
| Operating cost charges                                                      |       | 534,348    |       | 519,228    |       | 510,032    |       |
|                                                                        |       |       |       |       |       |       |       |
| Total Operating Expenses                                                    |       | 1,790,678  |       | 1,508,658  |       | 1,407,913  |       |
|                                                                        |       |       |       |       |       |       |       |
| Net Proceeds to the Trust                                                   |       | 16,388,781 |       | 12,940,550 |       | 11,769,597 |       |
|                                                                        |       |       |       |       |       |       |       |
| General and Administrative  Expenses                                        |       | (1,791,894 | )          | (1,002,397 | )          | (833,027   | )          |
|                                                                        |       |       |       |       |       |       |       |
| Interest Income                                                             |       | 500        |       | 1,489      |       | 953        |       |
|                                                                        |       |       |       |       |       |       |       |
| Cash Proceeds on Sale of Net  Profits Interests                             |       | —     |       | 80,205     |       | 10,293     |       |
|                                                                        |       |       |       |       |       |       |       |
| Distributable Income                                                        |       | 14,597,387 |       | 12,019,847 |       | 10,947,816 |       |
|                                                                        |       |       |       |       |       |       |       |
| Cash Reserve                                                                |       | (885,000   | )          | (100,000   | )          | (215,000   | )          |
|                                                                        |       |       |       |       |       |       |       |
| Distribution Amount                                                         |       | $          | 13,712,387 |       | $          | 11,919,847 |       | $ | 10,732,816 |   |
|                                                                        |       |       |       |       |       |       |       |
| Distributable Income Per Unit (5,900,000 units authorized and  outstanding) |       | $          | 2.4741     |       | $          | 2.0373     |       | $ | 1.8556 |   |
|                                                                        |       |       |       |       |       |       |       |
| Distribution Amount Per Unit (5,900,000 units authorized and  outstanding)  |       | $          | 2.3241     |       | $          | 2.0203     |       | $ | 1.8191 |   |

 

**The accompanying notes are an integral part ofthese financial statements.**

 

F-5

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**EASTERNAMERICAN NATURAL GAS TRUST**

**STATEMENTS OF CHANGES IN TRUSTCORPUS**

**for the years ended**

**December 31, 2005, 2004 and 2003**

 
| ** **                                               | ** ** | **2005**    | ** ** | **2004**    | ** ** | **2003**    | ** ** |
|----------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|
|                                                     |       |        |       |        |       |        |       |
| Trust Corpus, Beginning of  Period                       |       | $           | 31,139,508 |        | $          | 34,857,666  |       | $ | 38,695,799 |   |
| Distributable Income                                     |       | 14,597,387  |       | 12,019,847  |       | 10,947,816  |       |
| Distributions Paid or Payable  to Unitholders            |       | (13,712,387 | )          | (11,919,847 | )          | (10,732,816 | )          |
| Amortization of Net Profits  Interests in Gas Properties |       | (3,321,243  | )          | (3,818,158  | )          | (4,053,133  | )          |
|                                                     |       |        |       |        |       |        |       |
| Trust Corpus, End of Period                              |       | $           | 28,703,265 |        | $          | 31,139,508  |       | $ | 34,857,666 |   |

 

**The accompanying notes are an integral part ofthese financial statements.**

 

F-6

----

 

EASTERN AMERICAN NATURALGAS TRUST

NOTES TO FINANCIALSTATEMENTS

 

1.             Organization of the Trust:

 

The Eastern AmericanNatural Gas Trust (the “Trust”) was formed under the Delaware Business TrustAct pursuant to a Trust Agreement (the “Trust Agreement”) among EasternAmerican Energy Corporation (“Eastern American”), as grantor, Bank of MontrealTrust Company, as Trustee, and Wilmington Trust Company, as Delaware Trustee(the “Delaware Trustee”). Effective May 8, 2000, The Bank of New York acquiredthe corporate trust business of The Bank of Montreal Trust Company. As aresult, The Bank of New York served as Trustee (the “Trustee”). On November 20,2004, the holders of a majority of the Trust Units voting at a special meetingapproved the resignation of The Bank of New York as trustee and depository ofthe Trust and the appointment of JPMorgan Chase Bank, N.A. as successor trusteeof the Trust. The appointment of JPMorgan Chase Bank, N.A. as successor trusteebecame effective as of January 1, 2005. Consequently, references herein to the “Trustee”mean JPMorgan Chase Bank, N.A. as successor trustee, on and after January 1,2005. References to the “Trustee” at any time prior to January 1, 2005 mean TheBank of New York as trustee. Effective January 1, 2005, the transfer agent forthe Trust is Bondholder Communications.

 

The purpose of the Trustis to acquire and hold net profits interests owned by Eastern American in 650producing gas wells and 65 proved development well locations in West Virginiaand Pennsylvania (the “Underlying Properties”). The Underlying Properties areoperated by Eastern American. The Net Profits Interests (the “Net ProfitsInterests”) consist of a Royalty interest in 322 wells and a Term interest inthe remaining wells and locations. Eastern American drilled 59 of the 65development wells.

 

The Royalty NPI is notlimited in term or amount. Under the Trust Agreement, the Trustee is directed tosell all remaining Royalty NPI after May 15, 2012 and prior to May 15, 2013,and net proceeds from selling such Royalty NPI will be distributed toUnitholders on the first quarterly payment date following the receipt of suchproceeds by the Trust. The Term NPI will expire on the earlier of May 15, 2013or such time as 41,683 MMcf of gas has been produced which is attributable toEastern American’s net revenue interests in the properties burdened by the TermNPI. As of December 31, 2005, 21,814 MMcf of such gas had been produced.

 

Eastern American can sellthe Underlying Properties, subject to and burdened by the Net ProfitsInterests, without the consent of the Trustee or the Unitholders. In limitedcircumstances, Eastern American also can transfer the Underlying Properties andrequire the Trust to release the NPI burdening that property, without theconsent of the Trustee or Unitholders, subject to payment to the Trust of thefair value of the interest released. In addition, any abandonment of a well includedin the Underlying Properties or the Development Wells will extinguish thatportion of the Net Profits Interests that relate to such well.

 

Four (4) of the remainingsix (6) development wells were closely offset by third parties. Since the wellsdrilled by the third parties were within 1,000 feet of these development wells,Eastern American had a disagreement with the Trust over Eastern American’sobligation to drill these closely offset development wells. The Trust hasagreed that, in lieu of drilling these closely offset development wells EasternAmerican can provide the Trust, on an annual basis commencing on April 1, 1997,and over the remaining life of the Trust, a volume of gas which is equal to theprojected volumes of the wells as if they had been drilled. These volumes havebeen estimated by the Ryder Scott Company.

 

The two (2) remainingdevelopment wells were not drilled because Eastern American was unable to curevarious title defects associated with these wells. Eastern American advised theTrust that it made a diligent effort to cure title but was unsuccessful. InWest Virginia, an oil and gas well cannot be drilled unless a full and complete100% leasehold interest is first obtained. Drilling an oil and gas well withoutobtaining the entire leasehold estate would expose the oil and gas operator andthe Trust to a possible suit for trespass. Pursuant to the Term Net ProfitsInterest Conveyance, if the state of title to the drill site to any developmentwell renders such property undrillable in the good faith opinion of EasternAmerican under the Reasonably Prudent Operator Standard then such drill site(s)shall be construed as a development well(s). Consequently, Eastern American hasfulfilled its commitment to the Trust to drill the required number ofdevelopment wells.

 

On March 15, 1993,5,900,000 depositary units were issued in a public offering at an initialpublic offering price of $20.50 per depositary unit. Each depositary unitconsists of beneficial ownership of one unit of beneficial interest (“TrustUnit”) in the Trust and a $20 face amount beneficial ownership interest in a$1,000 face amount zero coupon United States Treasury Obligation (“TreasuryObligation”) maturing on May 15, 2013. Of the net proceeds from

 

F-7

----

 

EASTERN AMERICAN NATURALGAS TRUST

NOTES TO FINANCIALSTATEMENTS

 

such offering,$27,787,820 was used to purchase $118,000,000 in face amount of TreasuryObligations and $93,162,180 was paid to Eastern American in consideration forthe conveyance of the Net Profits Interests to the Trust. The Trust acquiredthe Net Profits Interests effective as of January 1, 1993. The TreasuryObligations are directly owned by the Unitholders and are not part of the TrustCorpus. The Treasury Obligations are on deposit with the Trustee pursuant tothe Deposit Agreement.

 

The Net Profits Interestsare passive in nature, and neither the Trustee nor the Delaware Trustee hasmanagement control or authority over, nor any responsibility relating to, theoperation of the properties subject to the Net Profits Interests. The TrustAgreement provides, among other things, that the Trust shall not engage in anybusiness or commercial activity or acquire any asset other than the Net ProfitsInterests initially conveyed to the Trust; the Trustee may establish a reservefor payment of any liability which is contingent, uncertain in amount or thatis not currently due and payable; the Trustee is authorized to borrow fundsrequired to pay liabilities of the Trust, provided that such borrowings arerepaid in full prior to further distributions to Unitholders; and the Trusteewill make quarterly cash distributions to Unitholders from funds of the Trust.

 

F-8

----

 

EASTERN AMERICAN NATURALGAS TRUST

NOTES TO FINANCIALSTATEMENTS

 

2.                                                          SignificantAccounting Policies:

 

The following is asummary of the significant accounting policies followed by the Trust.

 

*Basis of Accounting:*

 

The financial statementsof the Trust differ from financial statements prepared in accordance withaccounting principles generally accepted in the United States of America due tothe following; i) certain cash reserves may be established for contingencieswhich were not accrued in the financial statements; ii) amortization of the NetProfits Interests in gas properties is charged directly to Trust Corpus; andiii) the sale of the Net Profits Interests is reflected in the Statements ofDistributable Income as cash proceeds to the Trust.

 

*Cash:*

 

Cash consists of highlyliquid instruments with maturities at the time of acquisition of three monthsor less.

 

*Net Profits Interests in GasProperties:*

 

The Net Profits Interestsin gas properties are periodically assessed to determine whether their netcapitalized cost is impaired. The Trust will determine if a writedown isnecessary to its investment in the Net Profits Interests in gas properties tothe extent that total capitalized costs, less accumulated amortization, exceedundiscounted future net revenues attributable to proved gas reserves of theUnderlying Properties. The Trust will then provide a writedown to the extentthat the net capitalized costs exceed the discounted future net revenuesattributable to proved gas reserves of the Underlying Properties. Any suchwritedown would not reduce distributable income, although it would reduce TrustCorpus.

 

Significant dispositionsor abandonment of the Underlying Properties are charged to Net ProfitsInterests and the Trust Corpus.

 

Amortization of the NetProfits Interests in gas properties is calculated on a units-of-productionbasis, whereby the Trust’s cost basis in the properties is divided by totalTrust proved reserves to derive an amortization rate per reserve unit. Suchamortization does not reduce distributable income, rather it is chargeddirectly to Trust Corpus. Revisions to estimated future units-of-production aretreated on a prospective basis beginning on the date significant revisions areknown.

 

The conveyance of theRoyalty and Term Interests to the Trust was accounted for as a purchasetransaction. The $93,162,180 reflected in the Statements of Assets, Liabilitiesand Trust Corpus as Net Profits Interests in Gas Properties represents5,900,000 Trust Units valued at $20.50 per depository unit less the $27,787,820paid for Treasury obligations. The carrying value of the Trust’s investment inthe Royalty Interests is not necessarily indicative of the fair value of suchRoyalty Interests.

 

*Revenues and Expenses:*

 

The Trust serves as apass-through entity, with items of depletion, interest income and expense, andincome tax attributes being based upon the status and election of theUnitholders. Thus, the Statements of Distributable Income purport to showdistributable income, defined as Trust income available for distribution toUnitholders before application of those Unitholders’ additional expenses, ifany, for depletion, interest income and expense, and income taxes.

 

The Trust uses theaccrual basis to recognize revenue, with royalty income recorded as reservesare extracted from the Underlying Properties and sold. Expenses are alsorecognized on an accrual basis. Operating expenses which include taxes onproduction and operating cost charges are recognized as incurred pursuant tothe Conveyances on a per well production basis. The payment provisions of thegas purchase contract between the Trust and Eastern Marketing Corporationrequire payment with respect to gas production for a calendar quarter to bemade to the Trust on or before the tenth day of the third month following suchquarter.

 

F-9

----

 

EASTERN AMERICAN NATURALGAS TRUST

NOTES TO FINANCIALSTATEMENTS

 

*Use of Estimates in thePreparation of Financial Statements:*

 

The preparation offinancial statements requires the Trust to make estimates and assumptions thataffect the reported amounts of assets and liabilities and the reported amountsof revenues and expenses during the reporting period. Actual results coulddiffer from those estimates.

 

*Segment Information:*

 

In 1998, the Trust adopted Statement of Financial Accounting StandardsNo. 131, “Disclosure about Segments of an Enterprise and Related Information.”  The Trust’s sole activity is earning royaltyincome from gas properties and, consequently, the Trust has only one operatingsegment, net profits interests in gas properties. Substantially all of theTrust’s net profits interests are located in the Appalachian region.

 

3.             Income Taxes:

 

Tax counsel to EasternAmerican advised Eastern American at the time of formation that, under thencurrent tax laws, the Trust would be classified as a grantor trust for federaland state income tax purposes and, therefore, would not be subject to taxationat the Trust level. The Trust continues to be tax exempt. Accordingly, noprovision for federal or state income taxes has been made. However, the opinionof tax counsel is not binding on taxing authorities.

 

The Unitholders areconsidered, for income tax purposes, to own the Trust’s income and principal asthough no trust were in existence. Thus, the taxable year for reporting aUnitholder’s share of the Trust income, expense and credits are controlled bythe Unitholder’s taxable year and method of accounting, not the taxable yearand method of accounting employed by the Trust.

 

4.             Distributions to Unitholders:

 

The Trustee determinesfor each quarter the amount available for distribution to the Unitholders. Suchamount will be equal to the excess, if any, of the cash received by the Trust,on or before the tenth day of the third month following the end of eachcalendar quarter ending prior to the dissolution of the Trust, from the NetProfits Interests then held by the Trust attributable to production during suchquarter, plus, with certain exceptions, any other cash receipts of the Trustduring such quarter, over the liabilities of the Trust paid during suchquarter, subject to adjustments for changes made by the Trustee during suchquarter in any cash reserves established at the discretion of the Trustee forthe payment of contingent or future obligations of the Trust. Cash received bythe Trustee in a particular quarter from the Net Profits Interests will reflectactual gas production for a portion of such quarter and a production estimatefor the remainder of such quarter, such estimate to be adjusted to actualproduction in the following quarter. In accordance with the Trust Agreement andDelaware law, Unitholders should be shielded from direct liability for anyenvironmental liabilities. However, costs and expenses incurred by EasternAmerican for certain Capital Costs associated with environmental liabilitiesarising after the effective date of the Conveyances would reduce Net Proceeds,and would therefore be borne, in part, by the Unitholders.

 

Net Proceeds Receivableincluded in the Statements of Assets, Liabilities and Trust Corpus as ofDecember 31, 2005 are expected to be received by the Trust and distributed tothe Unitholders on March 15, 2006. The December 31, 2004 Net ProceedsReceivable were received and distributed by the Trust on March 16, 2005.

 

5.             Related Party Transactions:

 

The Trust is responsiblefor paying all legal, accounting, engineering and stock exchange fees, printingcosts and other administrative expenses incurred at the direction of the Trustee.The total of all Trustee fees and Trust administrative expenses was $1,474,570for the year ended December 31, 2005, $695,805 for the year ended December 31,2004, and $536,803 for the year ended December 31, 2003. In accordance with theTrust Agreement, the Trustee pays Eastern American an annual fee whichincreases by 3.5% per year, payable quarterly, to reimburse Eastern Americanfor overhead expenses. The initial fee at the inception of the Trust was$210,000. The Trustee paid Eastern American $317,324, $306,592 and $296,224 foroverhead expenses for 2005, 2004 and 2003 respectively. Operating cost chargesincluded in the Statements of Distributable Income are paid to EasternAmerican.

 

F-10

----

 

EASTERN AMERICAN NATURALGAS TRUST

NOTES TO FINANCIALSTATEMENTS

 

Gas productionattributable to the Net Profits Interests is purchased from the Trust byEastern Marketing Corporation (“Eastern Marketing”), a wholly owned subsidiaryof Eastern American, pursuant to a Gas Purchase Contract which effectivelycommenced as of January 1, 1993 and expires upon the termination of the Trust.

 

Pursuant to the GasPurchase Contract, Eastern Marketing is obligated to purchase such gasproduction at a purchase price per Mcf equal to the greater of the Index Price,as defined below, or a Floor Price, for gas produced in any quarter during thePrimary Term, which ended December 31, 1999. Effective January 1, 2000, EasternMarketing is obligated to purchase such gas production at a purchase price perMcf equal to the Index Price for gas produced in any quarter after the PrimaryTerm.

 

The Index Price for anyquarter subsequent to the Primary Term, which expired December 31, 1999, isdetermined solely by reference to the Variable Price component. The VariablePrice for any quarter is equal to the Henry Hub Average Spot Price (as defined)per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustmentfor Btu content. The Henry Hub Average Spot Price is defined as the price perMMBtu determined for any calendar quarter equal to the price obtained withrespect to each of the three months in such quarter, in the manner specifiedbelow, and then taking the average of the prices determined for each of suchthree months. The price determined for any month of such quarter is equal tothe average of (i) the final settlement prices per MMBtu for Henry Hub GasFutures Contracts (as defined), as reported in *The WallStreet Journal,*for such contracts which expired in each of the fivemonths prior to such month, (ii) the final settlement price per MMBtu for HenryHub Gas Futures Contracts, as reported in *The Wall Street Journal,*forsuch contracts which expire during such month and (iii) the closing settlementprices per MMBtu of Henry Hub Gas Futures Contracts determined as of thecontract settlement date for such month, as reported in *The WallStreet Journal,*for such contracts which expire in each of the sixmonths following such month. A Henry Hub Gas Futures Contract is defined as agas futures contract for gas to be delivered to the Henry Hub which is tradedon the New York Mercantile Exchange.

 

Under a standbyperformance agreement Eastern American has agreed to make payments under theGas Purchase Contract to the extent such payments are not made by EasternMarketing.

 

F-11

----

 

Supplemental ReserveInformation (Unaudited):

 

Information regardingestimates of the proved gas reserves attributable to the Trust are based onreports prepared by independent petroleum engineering consultants. Suchestimates were prepared in accordance with guidelines established by theSecurities and Exchange Commission. Accordingly, the estimates were based onexisting economic and operating conditions. Numerous uncertainties are inherentin estimating reserve volumes and values and such estimates are subject tochange as additional information becomes available.

 

The reserves actuallyrecovered and the timing of production of these reserves may be substantiallydifferent from the original estimates.

 

The standardized measureof discounted future net cash flows was determined based on reserve estimatesprepared by the independent petroleum engineering consultants. Fixed gas priceswere used during the Primary Term, which ended December 31, 1999. The gasprices used thereafter are based solely on the fourth quarter Variable Pricecomponent.

 

The reserves and revenuevalues for the Underlying Properties transferred to the Trust were estimatedfrom projections of reserves and revenue values attributable to the combinedEastern American and Trust interests in these properties. Reserve quantitiesare calculated differently for the Net Profits Interests because such interestsdo not entitle the Trust to a specific quantity of gas but to 90 percent of theNet Proceeds derived therefrom. Accordingly, there is no precise method ofallocating estimates of the quantities of proved reserves between those held bythe Trust and the interests to be retained by Eastern American. For purposes ofthis presentation, the proved reserves attributable to the Net ProfitsInterests have been proportionately reduced to reflect the future estimatedcosts and expenses deducted in the calculation of Net Proceeds with respect tothe Net Profits Interests. The reserves presented for the Net Profits Interestsreflect quantities of gas that are free of future costs or expenses. Theallocation of proved reserves between the Trust and Eastern American will varyin the future as relative estimates of future gross revenues and future costsand expenses vary.

 

The royalty portion ofthe Net Profits Interests was calculated beyond the liquidation date of theTrust (May 15, 2013), even though the terms of the Trust Agreement require thatthe Royalty Net Profits Interest be sold by the Trustee on or about this dateand a liquidating distribution from the sales proceeds from such sale would bemade to the Unitholders. The Term Net Profits Interests was limited to the20-year period as defined by the Trust Agreement.

 

F-12

----

 

The following tablereconciles the change in proved reserves attributable to the Trust’s share ofthe Net Profits Interests (“NPI”) from January 1, 2003 to December 31, 2005:

 
| ** **                      | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|---------------------------------|------------|------------------|------------|---------------|------------|----------------|------------|
| ** **                      | ** ** | **(MMcf)**       | ** ** | **(MMcf)**    | ** ** | **(MMcf)**     | ** ** |
|                            |       |             |       |          |       |           |       |
| Balance, January 1, 2003        |       | 12,025           |       | 8,609         |       | 20,634         |       |
|                            |       |             |       |          |       |           |       |
| Production                      |       | (932             | )          | (1,229        | )          | (2,161         | )          |
| Revisions of previous estimates |       | 201              |       | 87            |       | 288            |       |
|                            |       |             |       |          |       |           |       |
| Balance, December 31, 2003      |       | 11,294           |       | 7,467         |       | 18,761         |       |
|                            |       |             |       |          |       |           |       |
| Production                      |       | (910             | )          | (1,158        | )          | (2,068         | )          |
| Revisions of previous estimates |       | 1,072            |       | 393           |       | 1,464          |       |
|                            |       |             |       |          |       |           |       |
| Balance, December 31, 2004      |       | 11,456           |       | 6,702         |       | 18,158         |       |
|                            |       |             |       |          |       |           |       |
| Production                      |       | (849             | )          | (1,107        | )          | (1,956         | )          |
|                            |       |             |       |          |       |           |       |
| Revisions of previous estimates |       | 659              |       | 402           |       | 1,061          |       |
|                            |       |             |       |          |       |           |       |
| Balance, December 31, 2005      |       | 11,266           |       | 5,997         |       | 17,263         |       |

 

The Trust’s share of proved developed gas reserves are as follows:

 
| ** **        | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|-------------------|------------|------------------|------------|---------------|------------|----------------|------------|
| ** **        | ** ** | **(MMcf)**       | ** ** | **(MMcf)**    | ** ** | **(MMcf)**     | ** ** |
|              |       |             |       |          |       |           |       |
| December 31, 2003 |       | 11,294           |       | 7,467         |       | 18,761         |       |
|              |       |             |       |          |       |           |       |
| December 31, 2004 |       | 11,456           |       | 6,702         |       | 18,158         |       |
|              |       |             |       |          |       |           |       |
| December 31, 2005 |       | 11,266           |       | 5,997         |       | 17,263         |       |

 

F-13

----

 

Standardized Measure of DiscountedFuture Net Cash Flows Relating to Proved Reserves:

 

The following is thestandardized measure of discounted future net cash flows as of December 31,2005 (in thousands):

 
| ** **                                                | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|-----------------------------------------------------------|------------|------------------|------------|---------------|------------|----------------|------------|
|                                                      |       |             |       |          |       |           |       |
| Future cash inflows                                       |       | $                | 163,809    |          | $          | 83,267         |       | $ | 247,076 |   |
| Future production taxes                                   |       | (7,104           | )          | (3,146        | )          | (10,250        | )          |
| Future production costs                                   |       | (14,781          | )          | (4,581        | )          | (19,362        | )          |
|                                                      |       |             |       |          |       |           |       |
| Future net cash inflows                                   |       | 141,924          |       | 75,540        |       | 217,464        |       |
| 10% discount factor                                       |       | (82,646          | )          | (20,548       | )          | (101,194       | )          |
|                                                      |       |             |       |          |       |           |       |
| Standardized measure of discounted future net cash  flows |       | $                | 59,278     |          | $          | 54,992         |       | $ | 114,270 |   |

 

The following is thestandardized measure of discounted future net cash flows as of December 31,2004 (in thousands):

 
| ** **                                                | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|-----------------------------------------------------------|------------|------------------|------------|---------------|------------|----------------|------------|
|                                                      |       |             |       |          |       |           |       |
| Future cash inflows                                       |       | $                | 110,781    |          | $          | 60,830         |       | $ | 171,612 |   |
| Future production taxes                                   |       | (6,130           | )          | (2,942        | )          | (9,073         | )          |
| Future production costs                                   |       | (12,765          | )          | (4,130        | )          | (16,895        | )          |
|                                                      |       |             |       |          |       |           |       |
| Future net cash inflows                                   |       | 91,886           |       | 53,758        |       | 145,644        |       |
| 10% discount factor                                       |       | (53,480          | )          | (15,968       | )          | (69,448        | )          |
|                                                      |       |             |       |          |       |           |       |
| Standardized measure of discounted future net cash  flows |       | $                | 38,406     |          | $          | 37,790         |       | $ | 76,196 |   |

 

The following is thestandardized measure of discounted future net cash flows as of December 31,2003 (in thousands):

 
| ** **                                                | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|-----------------------------------------------------------|------------|------------------|------------|---------------|------------|----------------|------------|
|                                                      |       |             |       |          |       |           |       |
| Future cash inflows                                       |       | $                | 80,951     |          | $          | 49,043         |       | $ | 129,994 |   |
| Future production taxes                                   |       | (4,420           | )          | (2,333        | )          | (6,754         | )          |
| Future production costs                                   |       | (11,885          | )          | (3,967        | )          | (15,852        | )          |
|                                                      |       |             |       |          |       |           |       |
| Future net cash inflows                                   |       | 64,646           |       | 42,743        |       | 107,389        |       |
| 10% discount factor                                       |       | (37,289          | )          | (13,651       | )          | (50,940        | )          |
|                                                      |       |             |       |          |       |           |       |
| Standardized measure of discounted future net cash  flows |       | $                | 27,357     |          | $          | 29,092         |       | $ | 56,449 |   |

 

F-14

----

 

Changes in StandardizedMeasure of Discounted Future Net Cash Flows:

 

The following schedule reconciles the changes during 2003, 2004 and2005 in the standardized measure of discounted future net cash flows relatingto proved reserves (in thousands):

 
| ** **                               | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|------------------------------------------|------------|------------------|------------|---------------|------------|----------------|------------|
|                                     |       |             |       |          |       |           |       |
| Standardized measure, January 1, 2002    |       | $                | 22,953     |          | $          | 25,358         |       | $ | 48,311 |   |
| Net proceeds to the Trust                |       | (7,085           | )          | (4,684        | )          | (11,770        | )          |
| Revisions of previous estimates          |       | 1                |       | 0             |       | 1              |       |
| Accretion of discount                    |       | 2,295            |       | 2,536         |       | 4,831          |       |
| Net change in price and production costs |       | 7,405            |       | 4,926         |       | 12,331         |       |
| Other                                    |       | 1,788            |       | 956           |       | 2,745          |       |
|                                     |       |             |       |          |       |           |       |
| Standardized measure, December 31, 2003  |       | $                | 27,357     |          | $          | 29,092         |       | $ | 56,449 |   |
| Net proceeds to the Trust                |       | (8,164           | )          | (4,776        | )          | (12,941        | )          |
| Revisions of previous estimates          |       | 4,498            |       | 1,649         |       | 6,148          |       |
| Accretion of discount                    |       | 2,736            |       | 2,909         |       | 5,645          |       |
| Net change in price and production costs |       | 12,331           |       | 7,491         |       | 19,822         |       |
| Other                                    |       | (352             | )          | 1,425         |       | 1,073          |       |
|                                     |       |             |       |          |       |           |       |
| Standardized measure, December 31, 2004  |       | $                | 38,406     |          | $          | 37,790         |       | $ | 76,196 |   |
| Net proceeds to the Trust                |       | (11,864          | )          | (6,315        | )          | (18,179        | )          |
| Revisions of previous estimates          |       | 4,362            |       | 2,661         |       | 7,023          |       |
| Accretion of discount                    |       | 3,841            |       | 3,779         |       | 7,620          |       |
| Net change in price and production costs |       | 25,240           |       | 11,848        |       | 37,088         |       |
| Other                                    |       | (707             | )          | 5,229         |       | 4,522          |       |
|                                     |       |             |       |          |       |           |       |
| Standardized measure, December 31, 2005  |       | $                | 59,278     |          | $          | 54,992         |       | $ | 114,270 |   |

 

F-15

----

 

Quarterly Financial Data(Unaudited):

 

The following is asummary of royalty income and distributable income per unit by quarter in 2005,2004 and 2003 (all amounts in thousands except Distributable income per unit):

 
| **2005**                      | ** ** | **Mar 31** | ** ** | **June 30** | ** ** | **Sept 30** | ** ** | **Dec 31** | ** ** | **Total** | ** ** |
|-------------------------------|------------|------------|------------|-------------|------------|-------------|------------|------------|------------|-----------|------------|
|                          |       |       |       |        |       |        |       |       |       |      |       |
| Royalty income                |       | $          | 3,648      |        | $          | 3,914       |       | $          | 4,659      |      | $          | 5,958 |   | $ | 18,179 |   |
|                          |       |       |       |        |       |        |       |       |       |      |       |
| Distributable income          |       | $          | 2,958      |        | $          | 3,206       |       | $          | 3,800      |      | $          | 4,633 |   | $ | 14,597 |   |
|                          |       |       |       |        |       |        |       |       |       |      |       |
| Distributable income per unit |       | $          | 0.5014     |        | $          | 0.5434      |       | $          | 0.6440     |      | $          | 0.7853 |   | $ | 2.4741 |   |

 
| **2004**                      | ** ** | **Mar 31** | ** ** | **June 30** | ** ** | **Sept 30** | ** ** | **Dec 31** | ** ** | **Total** | ** ** |
|-------------------------------|------------|------------|------------|-------------|------------|-------------|------------|------------|------------|-----------|------------|
|                          |       |       |       |        |       |        |       |       |       |      |       |
| Royalty income                |       | $          | 3,080      |        | $          | 3,492       |       | $          | 3,452      |      | $          | 4,425 |   | $ | 14,449 |   |
|                          |       |       |       |        |       |        |       |       |       |      |       |
| Distributable income          |       | $          | 2,512      |        | $          | 3,019       |       | $          | 2,849      |      | $          | 3,640 |   | $ | 12,020 |   |
|                          |       |       |       |        |       |        |       |       |       |      |       |
| Distributable income per unit |       | $          | 0.4257     |        | $          | 0.5117      |       | $          | 0.4829     |      | $          | 0.6169 |   | $ | 2.0373 |   |

 
| **2003**                      | ** ** | **Mar 31** | ** ** | **June 30** | ** ** | **Sept 30** | ** ** | **Dec 31** | ** ** | **Total** | ** ** |
|-------------------------------|------------|------------|------------|-------------|------------|-------------|------------|------------|------------|-----------|------------|
|                          |       |       |       |        |       |        |       |       |       |      |       |
| Royalty income                |       | $          | 2,999      |        | $          | 3,645       |       | $          | 3,521      |      | $          | 3,012 |   | $ | 13,177 |   |
|                          |       |       |       |        |       |        |       |       |       |      |       |
| Distributable income          |       | $          | 2,363      |        | $          | 3,054       |       | $          | 3,014      |      | $          | 2,517 |   | $ | 10,948 |   |
|                          |       |       |       |        |       |        |       |       |       |      |       |
| Distributable income per unit |       | $          | 0.4005     |        | $          | 0.5175      |       | $          | 0.5109     |      | $          | 0.4266 |   | $ | 1.8556 |   |

 

F-16

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