**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**FORM 10-K**

| **x**      |   | **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES  EXCHANGE ACT OF 1934**                                                                                                            |
|------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** ** |   | ** **                                                                                                                                                                                           |
| ** ** |   | **FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006**                                                                                                                                                      |
| ** ** |   | ** **                                                                                                                                                                                           |
| **OR**     |
| ** ** |   |                                                                                                                                                                                                 |
| **o**      |   | **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934**                                                                                                        |
| ** ** |   | ** **                                                                                                                                                                                           |
| ** ** |   | **FOR THE TRANSITION PERIOD FROM                              TO** |

 

**Commission file number:1-11748**

**Eastern American Natural Gas Trust**

(Exact name of registrant asspecified in its Charter)

| **Delaware**                                                     |   | **36-7034603**                        |
|------------------------------------------------------------------|--------|---------------------------------------|
| (State or other  Jurisdiction of  Incorporation or Organization) |   | (I.R.S. Employer  Identification No.) |

 

**The Bank of New York TrustCompany, TrusteeGlobal Corporate Trust919 Congress Avenue Suite 500Austin, TX 78701**

(Address of principalexecutive office) (Zip Code)

**(800) 852-1422**

(Registrant’s telephonenumber, including area code)

Securities registeredpursuant 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                        |

 

Securities registered pursuant to Section12(g) of the Act:

**None**

Indicate by check mark if theregistrant is a well-known seasoned issuer, as defined in Rule 405 in the SecuritiesAct. Yes o No x

Indicate by check mark if theregistrant is not required to file reports pursuant to Section 13 or Section15(d) of the Exchange Act. Yes o No x

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 x 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 by reference in Part III of thisForm 10-K or any amendment to this Form 10-K. x

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  x           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 x

As of June 30, 2006,5,900,000 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, 19,900 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 market value ofthe Outstanding Units minus the Withdrawn Units at the closing sales price onJune 30, 2006 of $29.49 was approximately $173 million.

Documents Incorporated ByReference: **None**

 

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

 

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**PART I**

**Item 1.****    *Business***

**CautionaryStatement**

The Trustee (as defined below), its officers or itsagents on behalf of the Trustee may, from time to time, make forward-lookingstatements (other than statements of historical fact). In addition, this Reporton Form 10-K may contain forward-looking statements. When used herein, thewords “anticipates,” “expects,” “believes,” “intends” or “projects” and similarexpressions are intended to identify forward-looking statements. To the extentthat any forward-looking statements are made, the Trustee is unable to predictfuture changes in gas prices, gas production levels, economic activity,legislation and regulation, and certain changes in expenses of the Trust (asdefined below). In addition, the Trust’s future results of operations and otherforward-looking statements contained in this Item 1, Item 1A and elsewhere inthis report involve a number of risks and uncertainties. As a result ofvariations in such factors, actual results may differ materially from anyforward-looking statements. Some of these factors are described below. TheTrustee disclaims any obligations to update forward-looking statements and allsuch forward-looking statements in this document are expressly qualified intheir entirety by the cautionary statements in this paragraph.

**Definitions**

As used herein, the following terms have the meaningsindicated: “Mcf” means thousand cubic feet of gas, “MMcf” means million cubicfeet of gas, “Bbl” means barrel (approximately 42 U.S. gallons), and “MBbl”means thousand barrels, “Btu” means British thermal units and “MMBtu” or “Dth”means million British thermal units.

The following descriptions of the Eastern AmericanNatural Gas Trust (the “Trust”), the Depositary Units, the Net Profits Interests,the Underlying Properties and the calculation of amounts payable to the Trust,are subject to and qualified in their entirety by the more detailed provisionsof the Trust Agreement, the Depositary Agreement, the Conveyances and the GasPurchase Contract (each as defined below), all of which are incorporated byreference as exhibits to this Form 10-K and available upon request from theTrustee (as defined below) at the address set forth herein. The informationcontained herein relating to the operations of the Underlying Properties, aswell as information upon which the reserve figures and financial informationcontained herein were derived, was furnished to the Trustee by Eastern AmericanEnergy Corporation (“Eastern American”).

**DESCRIPTIONOF THE TRUST**

The Trust was formed under the Delaware Business TrustAct pursuant to a Trust Agreement (the “Trust Agreement”) among EasternAmerican, as grantor, Bank of Montreal Trust Company, as trustee, andWilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”).Effective May 8, 2000, The Bank of New York acquired the corporate trustbusiness 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, effective as of January 1, 2005.  Effective October 2, 2006, The Bank of NewYork Trust Company, N. A. replaced JPMorgan Chase Bank, N.A. as trustee inconnection with the sale by JPMorgan Chase Bank of substantially all of itscorporate trust business to The Bank of New York.  Consequently, references herein to the “Trustee”mean Bank of Montreal Trust Company until May 8, 2000; The Bank of New York assuccessor Trustee from May 8, 2000 through December 31, 2004; JPMorgan ChaseBank, N.A. as successor trustee, from January 1, 2005 through October 2, 2006;and The Bank of New York, N.A. as successor trustee, effective as of October 2,2006.  The transfer agent for the Trustis Bondholder Communications, an affiliate of The Bank of New York TrustCompany, N.A.

The Trust was formed to acquire and hold net profitsinterests (the “Net Profits Interests”) created from the working interestsowned by Eastern American in 650 producing gas wells and 65 proved developmentwell locations located in West Virginia and Pennsylvania (the “UnderlyingProperties”). A portion of the production from the wells burdened by the NetProfits Interests was intended to be eligible for credits (“Section 29 Credits”)under the Internal Revenue Code of 1986 for production of gas from Devonianshale or tight formations. The Net Profits Interests to be acquired consistedof a royalty interest in 322 wells and a term interest in the remaining wellsand development well locations. Eastern American was obligated to drill andcomplete, at its expense, 65 development wells (the “Development Wells”) on thedevelopment well locations conveyed to the Trust. Eastern American hasfulfilled its obligation with respect to the drilling of the Development Wells(see Note 1 of Financial Statements attached hereto). After May 15, 2012 andprior to or on May 15, 2013 (the “Liquidation Date”), the Trustee is requiredto sell the remaining royalty interests and liquidate the Trust.

On March 15, 1993, 5,900,000 Depositary Units wereissued in a public offering at an initial public offering price of $20.50 perDepositary Unit. Each Depositary Unit consists of beneficial ownership of oneunit of beneficial interest (“Trust

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Unit”)in the Trust and a $20 face amount beneficial ownership interest in a $1,000face amount zero coupon United States Treasury obligation (“Treasury Obligation”)maturing on May 15, 2013. Holders of Depositary Units (“Unitholders”) maywithdraw 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 Trust acquiredthe Net Profits Interests effective as of January 1, 1993.

The Net Profits Interests are passive in nature, andneither the Trustee nor the Delaware Trustee has management control orauthority over, nor any responsibility relating to, the operation of theUnderlying Properties (defined above) subject to the Net Profits Interests. TheTrust Agreement provides, among other things, that: the Trust shall not engagein any business or commercial activity or acquire any asset other than the NetProfits Interests initially conveyed to the Trust; the Trustee may establish areserve for payment of any liability which is contingent, uncertain in amountor that is not currently due and payable; the Trustee is authorized to borrowfunds required to pay liabilities of the Trust, provided that such borrowingsare repaid in full prior to further distributions to Unitholders and otherholders of Trust Units (together, “Trust Unitholders”); and the Trustee willmake quarterly cash distributions to Trust Unitholders from funds of the Trust.

The Trust is responsiblefor paying the Trustee’s fees and all legal, accounting, engineering and stockexchange fees, printing costs and other administrative expenses incurred by orat the direction of the Trustee. The total fees paid to the Trustee for 2006were $108,000. The total of all Trustee fees and Trust administrative expensesfor 2006 was $1,317,881. Such costs could fluctuate in the future dependingprimarily on the expenses the Trust incurs for professional services, particularlylegal, accounting and engineering services. In addition to such expenses, in2006, the Trust paid Eastern American an overhead reimbursement of $328,432.The overhead reimbursement was established at the inception of the Trust,increases by 3.5% per year, and is payable quarterly.

**THE NET PROFITS INTERESTS**

**TheConveyances**

The Net Profits Interests (“NPI”) were created fromthe Underlying Properties and conveyed to the Trust pursuant to two Conveyances- one conveying a royalty interest in specified wells (the “Royalty NPIConveyance”) and the other conveying the a term interest in specified wells(the “Term NPI Conveyance”, and together with the Royalty NPI Conveyance, the “Conveyances”).Forms of the Conveyances have been incorporated by reference as exhibits tothis report.

The Underlying Properties are subject to and burdenedby the Net Profits Interests. The interests of Eastern American comprising theUnderlying Properties represent, on average, a working interest ofapproximately 90% and a net revenue interest of approximately 76%. TheConveyances provide that the Trust is only entitled to gas produced from thespecific wells identified in the Conveyances and is not entitled to any gasproduced from adjacent wells (including adjacent wells subject to the samelease or farmout agreement as the wells subject to the Net Profits Interests).Gas produced from the Underlying Properties which is attributable to the NetProfits Interests is purchased from the Trust by Eastern Marketing Corporation(“Eastern Marketing”), a wholly-owned subsidiary of Eastern American, pursuantto a gas purchase contract (the “Gas Purchase Contract”). The volumesattributable to the Net Profits Interests and the purchase price for such gasis calculated for each calendar quarter, and payment for such gas is made tothe Trust not later than the tenth day of the third calendar month followingthe end of each calendar quarter.

The Royalty NPI is not limited in term or amount.Under the Trust Agreement, the Trustee is directed to sell all remainingRoyalty NPI after May 15, 2012 and prior to May 15, 2013, and net proceeds fromselling such Royalty NPI will be distributed to Unitholders on the firstquarterly payment date following the receipt of such proceeds by the Trust. TheTerm NPI will expire on the earlier of May 15, 2013 or such time as 41,683 MMcfof gas has been produced which is attributable to Eastern American’s netrevenue interests in the properties burdened by the Term NPI. As of December31, 2006, 23,661 MMcf of such gas had been produced. The Trust is expected toterminate in 2013. See “Description of Trust Units and Depository Units –Liquidation of the Trust”.

Eastern American can sell the Underlying Properties,subject to and burdened by the Net Profits Interests, without the consent ofthe Trustee or the Unitholders. In limited circumstances, Eastern American alsocan transfer the Underlying Properties and require the Trust to release the NPIburdening that property, without the consent of the Trustee or Unitholders,subject to payment to the Trust of the fair value of the interest released. Inaddition, any abandonment of a well included in the Underlying Properties orthe Development Wells will extinguish that portion of the Net Profits Intereststhat relate to such well. See “Sale and Abandonment of Underlying Properties;Sale of Royalty NPI.”

**Calculationof Net Proceeds**

The definitions, formulas, accounting procedures andother terms governing the computation of Net Proceeds are

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detailedand extensive, and reference is made to both the Royalty NPI Conveyance and theTerm NPI Conveyance for a more detailed discussion of the computation thereof.

The Conveyances and the Gas Purchase Contract entitlethe Trust to receive an amount of cash for each calendar quarter equal to theNet Proceeds for such quarter. “Net Proceeds” for any calendar quartergenerally means an amount of cash equal to (a) 90% of a volume of gas equal to(i) the volume of gas produced during such quarter attributable to theUnderlying Properties less (ii) a volume of gas equal to Chargeable Costs, asdefined below, for such quarter, multiplied by (b) the applicable price forsuch quarter under the Gas Purchase Contract. If, for any reason, the GasPurchase Contract terminates prior to the Liquidation Date, “Net Proceeds” willmean an amount of cash equal to (a) 90% of a volume of gas equal to (i) thevolume of gas produced during such quarter attributable to the UnderlyingProperties less (ii) a volume of gas equal to Chargeable Costs for such quarter,multiplied by (b) the applicable price for such quarter determined inaccordance with the Conveyances. Pursuant to the Conveyances, the Trust is notentitled to receive any natural gas liquids produced from the UnderlyingProperties or any proceeds relating thereto.

“Chargeable Costs” is that volume of gas which equatesin value, determined by reference to the relevant sales price under the GasPurchase Contract or the Conveyances, as applicable, to the sum of the “OperatingCost Charge”, “Capital Costs” and “Taxes” (as defined in the Conveyances). TheOperating Cost Charge for 2006 was $561,068, for 2005 was $534,348 and for 2004was $519,228. As provided in the Conveyances, the Operating Cost Charge willincrease based on the lesser of (A) five percent (5%) or (B) a percentage, notless than zero percent (0%), equal to the percentage increase, if any, in theaverage weekly earnings of Crude Petroleum and Gas Production Workers for thelast calendar year, as shown by the index of average weekly earnings of CrudePetroleum and Gas Production Workers, as published by the United StatesDepartment of Labor, Bureau of Labor Statistics, based on December-to-Decembercomparison.

During 2003, the United States Department of Labor,Bureau of Labor Statistics converted all of its industry-based statistics to adifferent reporting system that was developed in cooperation with the UnitedStates’ North American Free Trade Agreement Partners, Canada and Mexico, in aneffort to standardize and modernize reporting codes. As a result of thisconversion, the Crude Petroleum and Gas Production Workers index is no longeravailable for use in the annual calculation of overhead adjustment called forin the various Council of Petroleum Accountants Societies, or COPAS, model formsafter March 2003.

Researchby COPAS covering a ten year period indicated that by blending the Oil and GasExtraction Index with the Professional and Technical Services Index, theresults approximate the data from the old Crude Petroleum and Natural Gas WorkersIndex. Accordingly, COPAS has calculated the percentage change in the simpleaverage of the Oil and Extraction Index and the Professional and TechnicalServices Index, commencing in April 2004. This “Overhead Adjustment Index” hasbeen provided as a guidance to the industry as a replacement index for use incalculating the overhead adjustment. The adjustment for the effective timeperiod is 3.5%. Since the Conveyance Documents do not specifically provide fora replacement index if the Crude Petroleum and Gas Production Workers Index wasno longer published, Eastern American believes, and advised the Trustee, thatthe “Overhead Adjustment Index” as calculated by COPAS is a reasonable index toutilize since the industry is generally adopting the same as a replacement.Eastern American, with the concurrence of the Trustee, will utilize this “OverheadAdjustment Index” to adjust the “Operating Cost Charge” so long as such indexis published by COPAS.

The Operating Cost Charge will be reduced for eachwell that is sold (free of the Net Profits Interests) or plugged and abandoned.Capital Costs are defined as Eastern American’s working interest share ofcapital costs for operations on the Underlying Properties having a useful lifeof at least three years, and excluding any capital costs incurred in drillingthe Development Wells. Taxes refer to ad valorem taxes, production andseverance taxes, and other taxes imposed on Eastern American’s or the Trust’sinterests in the Underlying Properties, or production therefrom.

Although the Trust bearsthe full economic burden of Chargeable Costs, it does so indirectly in thecalculation of Net Proceeds and the Trust is not directly liable for any shareof the costs, risks, and liabilities associated with the ownership or operationof the Underlying Properties. If the Trust ever receives payments in excess ofthe Net Proceeds or other amounts it was not entitled to receive, the Trustwill not be required to refund the money, but Eastern American may recover theamount of such overpayments from future distributions in accordance with theConveyances.

The Conveyances require Eastern American to maintainbooks, records, and accounts sufficient to calculate the volumes of gas and theshare of Net Proceeds payable to the Trust. Eastern American provides to theTrust quarterly and annual statements of applicable production, revenues, andcosts necessary for the Trust to prepare quarterly and annual financialstatements with respect to the Net Profits Interests and the Underlying Properties.The financial statements of the Trust are audited annually at the Trust’sexpense.

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**GasPurchase Contract**

Gas production attributable to the Net ProfitsInterests is purchased from the Trust by Eastern Marketing, a wholly ownedsubsidiary of Eastern American, pursuant to the Gas Purchase Contract whicheffectively commenced as of January 1, 1993 and expires upon the termination ofthe Trust.

Under the Gas Purchase Contract, Eastern Marketingpurchases gas from the Trust at a variable price for each quarter equal to theHenry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu,multiplied by 110% to effect a fixed adjustment for Btu content. The Henry HubAverage Spot Price is defined as the price per MMBtu determined for any calendarquarter equal to the price obtained with respect to each of the three months insuch quarter, in the manner specified below, and then taking the average of theprices determined for each of such three months. The price determined for anymonth of such quarter is equal to the average of (i) the final settlementprices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reportedin *The Wall Street Journal,*for suchcontracts which expired in each of the five months prior to such month, (ii)the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, asreported in *The Wall Street Journal,*for suchcontracts 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 price paidto 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 Agreement provides that the Trustee may notagree to any amendment to the Gas Purchase Contract which would materially andadversely affect the revenues to the Trust without the approval of the holdersof a majority of the outstanding Trust Units. The Trust Agreement also providesthat the Gas Purchase Contract may not be terminated by the Trust without theapproval of the holders of a majority of the outstanding Trust Units. The GasPurchase Contract and the Trust Agreement have been filed as exhibits to thisForm 10-K. The foregoing summary of the principal provisions of the GasPurchase Contract, and certain provisions of the Trust Agreement, is qualifiedin its entirety by reference to the terms of such agreements as set forth insuch exhibits.

Eastern Marketing’s rights and obligations under theGas Purchase Contract are assignable under circumstances where the assigneeunconditionally assumes Eastern Marketing’s obligations under the Gas PurchaseContract only if such assignee (or assignee’s parent corporation if such parentguarantees the assignee’s obligations) has a rating assigned to its unsecuredlong-term debt by Moody’s Investor Service of at least Baa+ and by Standard& Poor’s Corporation of at least BBB-. Under such circumstances, EasternMarketing and Eastern American would be released from their obligations underthe Gas Purchase Contract.

**PerformanceSupport for Gas Purchase Contract**

Gas production attributable to the Net ProfitsInterests will be purchased by Eastern Marketing pursuant to the Gas PurchaseContract, which expires upon the Liquidation Date of the Trust. EasternAmerican has agreed to make payments under a standby performance agreement tothe extent such payments are not made by Eastern Marketing under the GasPurchase Contract.

**Distributionsand Income Computations**

The Trustee determines for each quarter the amount ofcash available for distribution to holders of Depositary Units and the TrustUnits evidenced thereby. Such amount (the “Quarterly Distribution Amount”) isequal to the excess, if any, of (i) the cash that the Trust receives on orbefore the tenth day of the third month after the end of each calendar quarterending before the Trust is dissolved and that is attributable to productionfrom the Net Profits Interest held by the Trust during that calendar quarter,plus, with certain exceptions, any other cash receipts of the Trust during suchquarter, over (ii) the liabilities of the Trust paid during such quarter,subject to adjustments for changes made by the Trustee during such quarter inany cash reserves established for the payment of contingent or futureobligations of the Trust. Quarterly Distribution Amounts for each of thequarters in 2006 were $0.74, $0.64, $0.65, and $0.45 respectively. Based on thepayment procedures relating to the Net Profits Interests, cash received by theTrustee in a particular quarter from the Net Profits Interests reflects actualgas production for a portion of such quarter and a production estimate for theremainder of such quarter, such estimate to be adjusted to actual production inthe following quarter. The Quarterly Distribution Amount for each quarter ispayable to Unitholders of record on the last day of the second month followingthe end of such calendar quarter or such later date as the Trustee determinesis required to comply with legal or stock exchange requirements (“QuarterlyRecord Date”). It is expected

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thatthe Trustee will continue to be able to distribute cash on or before the 15thday (or the next succeeding business day following such day if such day is nota business day) of the third month following the end of each calendar quarterto each 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 of the Trust for each calendarquarter is reported by the Trustee for tax purposes as belonging to the holdersof record to whom the Quarterly Distribution Amount was or will be distributed.Assuming that the Trust will be classified for tax purposes as a “grantortrust,” the net taxable income will be realized by the holders for tax purposesin the calendar quarter received by the Trustee, rather than in the quarterdistributed by the Trustee. Thus, a Unitholder’s taxable income for a taxableyear may differ from the cash the Unitholder receives during that year. Inaddition, taxable income of a holder will differ from the QuarterlyDistribution Amount because the Treasury Obligations will be treated asgenerating interest income for tax purposes. There may also be minor variancesbecause of the possibilities that a reserve will be established in one quarterthat will not give rise to a tax deduction until a subsequent quarter, anexpenditure paid for in one quarter will have to be amortized for tax purposesover several quarters, or for other reasons. 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 in accordance with the TrustAgreement will be entitled to receive a liquidating distribution equal to a prorata portion of the net proceeds from the sale of the Royalty NPI (to the extentnot previously distributed) and a pro rata portion of the proceeds from thematured Treasury Obligations.

**Sale andAbandonment of Underlying Properties; Sale of Royalty NPI**

Eastern American and anytransferees have the right to abandon any well or working interest included inthe Underlying Properties if, in its opinion, such well or property ceases toproduce or is not capable of producing in commercially paying quantities. Toreduce or eliminate the potential conflict of interest between Eastern Americanand the Trust in determining whether a well is capable of producing in payingquantities, Eastern American is required under the Conveyances to make any suchdetermination as would a reasonably prudent operator in the Appalachian Basinif it were acting with respect to its own properties, disregarding (i) theexistence of the Net Profits Interests as a burden on such property and (ii)the direct or indirect effect, financial or otherwise, on Eastern American orany of its affiliates that may result from the performance by Eastern Marketingof its obligations under the Gas Purchase Contract.

Eastern American has theright, 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 setforth in the preceding paragraph.

Eastern American may sellthe 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 required to sell all of the Royalty NPIafter May 15, 2012 and prior to the Liquidation Date. The proceeds of suchsale, together with the matured face amount of the Treasury Obligations, willbe distributed to Unitholders on or prior to the Liquidation Date. Under theTrust Agreement, Eastern American has a right of first refusal to purchase anyof the Royalty NPI at the fair value to the Trust, or if applicable the offeredthird-party price, prior to the Liquidation Date.

**THEUNDERLYING PROPERTIES**

**General**

The Underlying Properties are comprised of EasternAmerican’s working interests in certain properties located in the AppalachianBasin states of West Virginia and Pennsylvania. As of December 31, 2006, suchproperties consisted of 670 producing gas wells. The working interests ofEastern American comprising the Underlying Properties are held under leases andfarmout agreements with third parties. Such working interests are subject tolandowner’s royalties (typically 12-1/2%)

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andmay be subject to additional royalties or other obligations burdening theworking interests. Such royalties do not bear lease operating expenses, butreduce the revenue interests attributable to the Underlying Properties. EasternAmerican’s interests comprising the Underlying Properties represent, onaverage, a working interest of approximately 90% and a net revenue interest ofapproximately 76%. As of December 31, 2006, proved developed reservesattributable to the Net Profits Interests (reflecting quantities of gas free offuture costs and expenses based on estimated prices) were approximately 14,699MMcf. (See “Reserves”).

The Appalachian Basin is a mature producing regionwith well known geologic characteristics. Substantially all of the wellscomprising the Underlying Properties are relatively shallow, ranging from 2,500to 5,500 feet, and many are completed to multiple producing zones. In general,the wells to which the Underlying Properties relate are proved producingproperties with stable production profiles and generally long-lived production,often with total projected economic lives in excess of 25 years. Once drilledand completed, ongoing operating and maintenance requirements are low and onlyminimal, if any, capital expenditures are typically required.

The Underlying Properties initially included 65specified development well locations for the drilling of the Development Wellsby Eastern American. Eastern American was obligated to bear the costs ofdrilling and completing the Development Wells. Eastern American has fulfilledits obligation with respect to the drilling of the Development Wells. See Note1 of Financial Statements attached hereto.

Eastern American acquired its interests in theUnderlying Properties under or through (i) oil and gas leases granted by themineral owner directly to Eastern American, (ii) assignments of oil and gasleases by the lessee who originally obtained the leases from the mineral owner,(iii) farmout agreements that grant Eastern American the right to earninterests in the properties covered by such agreements by drilling wells and(iv) the acquisitions of oil and gas interests by Eastern American.

Production from the wells to which the UnderlyingProperties relate is typically subject to (i) landowner royalties and otherburdens and obligations retained under oil and gas leases, (ii) overridingroyalty interests and (iii) interests of other working interest owners in thewells. The royalty and overriding interests entitle the holders thereof to acertain percentage of the oil and gas produced from the wells or the proceedstherefrom and are generally delivered free of all expenses of production butmay be subject to post-production costs, such as production or gathering taxes,costs to treat the gas to render it marketable, and certain transportation orgathering costs. Royalty interests are usually reserved by the lessor under anoil and gas lease. Overriding royalty interests are carved out of a lessee’sshare of production under an oil and gas lease and are generally reserved by apredecessor in title or reserved under farmout agreements.

A farmout agreement is typically an agreement underwhich a lessee under an oil and gas lease (the “Farmor”) grants to anotherparty the right to drill wells on the tract covered by such lease and to earncertain acreage for drilling such wells. In the Appalachian Basin, the Farmorgenerally receives a well location fee and reserves an overriding royaltyinterest in the wells which typically ranges from 3.25% to 6.25%. Farmoutagreements typically provide that wells must be drilled and completed as acondition to a transfer by the Farmor of the interest in the underlying lease.

**Reserves**

*Proved Reserves of Underlying Properties and NetProfits Interests.*The following table sets forth, as ofDecember 31, 2006, certain estimated proved reserves, estimated future netrevenues and the discounted present value thereof attributable to theUnderlying Properties, the Royalty NPI and the Term NPI, in each case derivedfrom a report of oil and gas reserves attributable to the Trust as of December31, 2006 prepared by Ryder Scott Company (the “Reserve Report”). Proved reservequantities attributable to the Net Profits Interests are calculated bysubtracting an amount of gas sufficient, if sold at the prices used inpreparing the reserve estimates, to pay the future estimated costs and expensesdeducted in the calculation of Net Proceeds. Accordingly, the reservesattributable to the Net Profits Interests reflect quantities of gas that arefree of future costs or expenses if the price and cost assumptions set forth inthe Reserve Report occur. A decrease in the price assumption, or an increase inthe cost assumption used in the Reserve Report would reduce the estimates ofproved reserves, future net revenues and discounted future net revenues, setforth herein and in the Reserve Report. The Term NPI excludes production beyondthe earlier of May 15, 2013 or such time as 41,683 MMcf of gas has beenproduced which is attributable to Eastern American’s net revenue interests inthe properties burdened by the Term NPI. The discounted present value ofestimated future net revenues was determined using a discount rate of 10% inaccordance 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) |       | 31,802                            |       | 0                       |       | 31,802                    |       | $ | 215,728 |   | $ | 88,414 |   |
|                      |       |                              |       |                    |       |                      |       |   |   |   |   |
| Net Profits Interests:    |       |                              |       |                    |       |                      |       |   |   |   |   |
| Royalty NPI               |       | 9,885                             |       | 0                       |       | 9,885                     |       | $ | 80,027 |   | $ | 33,779 |   |
| Term NPI                  |       | 4,814                             |       | 0                       |       | 4,814                     |       | 38,977 |   | 29,481 |   |
|                      |       |                              |       |                    |       |                      |       |   |   |   |   |
| Total                     |       | 14,699                            |       | 0                       |       | 14,699                    |       | $ | 119,004 |   | $ | 63,260 |   |

 

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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 the DepositaryUnits and the Trust Units evidenced thereby are substantially dependent uponthe proved reserves and production levels attributable to the Net ProfitsInterests. There are many uncertainties inherent in estimating quantities andvalues of proved reserves and in projecting future rates of production and thetiming of development expenditures, if any. The reserve data set forth herein,although prepared by independent engineers in a manner customary in theindustry, are estimates only, and actual quantities and values of gas arelikely to differ from the estimated amounts set forth herein. In addition, thediscounted present values shown herein were prepared using guidelinesestablished by the Securities and Exchange Commission (the “Commission”) andthe Financial Accounting Standards Board for disclosure of reserves and shouldnot be considered representative of the market value of such reserves or theDepositary Units or the Trust Units evidenced thereby. A market valuedetermination would include many additional factors.

**COMPETITIONAND MARKETS**

All of the production attributable to the Net ProfitsInterest is sold to Eastern Marketing pursuant to the Gas Purchase Contract.See “The Net Profits Interests - Gas Purchase Contract.”

**REGULATIONOF NATURAL GAS**

The natural gas industry has historically been highlyregulated by state and federal authorities. In the past, concerns aboutperceived pipeline monopolies and other factors caused Congress to imposeeconomic regulation on both pipelines and producers. Federal agencies regulatedtariffs and conditions of service offered by interstate pipelines, and setmaximum prices on the wellhead price of natural gas sold into interstatecommerce. States, and even local governments, also regulated retail sales ofnatural gas by local utilities. Government agencies also set production ratesto avoid waste and imposed environmental and safety regulations. At present, itappears that Federal regulation of wellhead natural gas prices has ended.However, there can be no assurance that price controls or other similareconomic regulations may not be reimposed in the future.

Drilling and production of natural gas are heavilyregulated in Pennsylvania and West Virginia, as in most states. A well cannotbe drilled without a permit, and operations must be conducted in compliancewith environmental, safety and conservation laws and regulations. In contrastto many other states which have substantial oil and gas production activity,the spacing of shallow wells (such as the wells subject to the Net ProfitsInterests) is not regulated by any state statute or regulatory agency in eitherWest Virginia or Pennsylvania. Without spacing requirements specified by statestatute or regulation, drainage of reserves from a property may occur from wellslocated in close proximity to such property.

**HEALTH,SAFETY, AND ENVIRONMENTAL REGULATION**

*General.*Activities on theUnderlying Properties are subject to existing Federal, state and local laws andregulations governing health, safety, environmental quality and pollutioncontrol. It is anticipated that, absent the occurrence of an extraordinaryevent, compliance with existing Federal, state and local laws, rules andregulations regulating health, safety, the discharge of materials into theenvironment or otherwise relating to the protection of the environment will nothave a material adverse effect upon the Trust. It cannot be predicted whateffect additional regulation or legislation, enforcement policies thereunder,and claims for damages to property, employees, other persons and theenvironment resulting from operations on

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theUnderlying Properties could have on the Trust. However, pursuant to the termsof the Conveyances, any costs or expenses incurred in connection withenvironmental liabilities of Eastern American arising out of or related toactivities occurring on or in, or conditions existing on or under, theUnderlying Properties before the effective date of the Conveyances will beborne by Eastern American and will not be deducted in calculating Net Proceedsattributable to the Net Profits Interests. Additionally, because Unitholderswill have limited liability in accordance with the Trust Agreement and Delawarelaw, Unitholders should be shielded from direct liability for any environmentalliabilities. See “Description of Trust Units and Depositary Units—Liability ofUnitholders.” However, costs and expenses incurred by Eastern American forcertain Capital Costs associated with environmental liabilities arising afterthe effective date of the Conveyances would reduce Net Proceeds, and wouldtherefore be borne, in part, by the Unitholders. The following subtopicsdiscuss some of the principal forms of health, safety, and environmentalregulation to which the Underlying Properties and operations thereon aresubject. The costs of complying with these regulatory requirements may burdenthe Net Profits Interests to the extent they arise out of or are related toactivities occurring on or in, or conditions existing on or under, theUnderlying Properties after the effective date of the Conveyances.

*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 arelatively short period of time prior to the effective date of the Conveyances.Eastern American has informed us they have no knowledge of prior operatorsutilizing operating and disposal practices that were not standard in theindustry at the time nor have hydrocarbons or other solid or hazardous wastesmay have been disposed of or released on or under the Underlying Properties.Federal, state and local laws applicable to gas-related wastes have becomeincreasingly more stringent. Under current laws, Eastern American or the operatorof the Underlying Properties could be required to remove or remediatepreviously disposed wastes or property contamination (including groundwatercontamination) or to perform remedial plugging operations to prevent futurecontamination.

The operations of the Underlying Properties maygenerate wastes that are subject to the Federal Resource Conservation andRecovery Act (“RCRA”) and comparable state statutes. The EnvironmentalProtection Agency (the “EPA”) has limited the disposal options for certainhazardous wastes and may adopt more stringent disposal standards fornonhazardous wastes.

*Superfund.*The ComprehensiveEnvironmental Response, Compensation and Liability Act (“CERCLA”), also knownas the “superfund” law, imposes liability, regardless of fault or the legalityof the original conduct, on certain classes of persons that contributed to therelease of a “hazardous substance” into the environment. These persons includethe current or previous owner and operator of a site and companies thatdisposed or arranged for the disposal of, the hazardous substance found at asite. CERCLA also authorizes the EPA and, in some cases, private parties totake actions in response to threats to the public health or the environment andto seek recovery from such responsible classes of persons of the costs of suchaction. In the course of their operations, the operators of the UnderlyingProperties have generated and will generate wastes that may fall within CERCLA’sdefinition of “hazardous substances”. Eastern American or the previous operatorof the Underlying Properties may be responsible under CERCLA for all or part ofthe costs to clean up sites at which such substances have been disposed.

*Air Emissions.*The operations ofthe Underlying Properties are subject to Federal, state and local regulationsconcerning the control of emissions from sources of air contaminants.Administrative enforcement actions for failure to comply strictly with airregulations or permits are generally resolved by payment of a monetary penalty andcorrection of any identified deficiencies. Regulatory agencies could requirethe operators to forego or modify construction or operation of certain airemission sources.

*OSHA.*The operations of theUnderlying Properties are subject to the requirements of the FederalOccupational Safety and Health Act (“OSHA”) and comparable state statutes. TheOSHA hazard communication standard, the EPA community right-to-know regulationsunder Title III of the Federal Superfund Amendment and Reauthorization Act andsimilar state statutes require that information be organized and maintainedabout hazardous materials used or produced in the operations. Certain of thisinformation must be provided to employees, state and local governmentauthorities and citizens.

**DESCRIPTIONOF TRUST UNITS AND DEPOSITARY UNITS**

The following information is subject to the detailedprovisions of the Deposit Agreement originally entered into by EasternAmerican, the Trustee, and Bank of Montreal Trust Company, as Depositary (the “Depositary”)and all holders from time to time of Depositary Units (the “Deposit Agreement”),a copy of which is filed as an exhibit to this Form 10-K.

The functions of the Depositary under the DepositAgreement are custodial and ministerial in nature and for the benefit ofUnitholders. The Deposit Agreement and the issuance of Depositary Unitsthereunder provide Unitholders an administratively convenient form of holdingan investment in the Trust and a Treasury Obligation. Each Depositary Unit isevidenced by a certificate, which is issued by the Depositary and transferableonly in denominations of 50 Depositary Units

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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 Units and Treasury Obligations areheld solely for the benefit of the Unitholders and do not constitute assets ofthe Depositary or the Trust. The Depositary has no power to assign, transfer,pledge or otherwise dispose of any of the Trust Units or Treasury Obligations,except in the limited instances provided in the Deposit Agreement.

Generally, the holders of Depositary Units areentitled to participate in distributions with respect to the Trust Units, theTreasury Obligations and to the liquidation of the remaining assets of theTrust.

**Withdrawalof Trust Units and Restrictions on Transfer**

Upon presentation of Depositary Units in denominationsof 50 or integral multiples thereof for withdrawal of the Trust Units anddiscrete Treasury Obligations evidenced thereby in accordance with the DepositAgreement, the Unitholder will receive an uncertificated direct interest inTrust Units. These withdrawn Trust Units will be evidenced on the books of theTrustee by a transfer of such Trust Units from the name of the Depositary tothe name of the withdrawing Unitholder. Holders of withdrawn Trust Units willbe entitled to receive Trust distributions and periodic Trust information(including tax information) directly from the Trustee. Moreover, holders ofTrust Units will be entitled to each of the rights accorded Unitholders underthe Trust Agreement, including voting and liquidation rights, as elsewheredescribed herein, except that withdrawn Trust Units are not freely transferableas described below.

Pursuant to the Trust Agreement and the transferapplication for transfer of the Trust Units, withdrawn Trust Units are nottransferable except by operation of law. A holder of withdrawn Trust Units may,however, transfer such Trust Units in denominations of 50 (or integralmultiples thereof) to the Depositary for redeposit, together with TreasuryObligations in the face amount equal to $1,000 for each 50 Trust Unitsredeposited, in exchange for Depositary Units. Such redeposit may be effectedby delivering written notice of such transfer jointly to the Depositary and theTrustee together with proper documentation necessary to transfer the requisiteTreasury Obligations into the name of the Depositary.

**Distributionsand Income Computations**

The Trustee determines for each quarter the QuarterlyDistribution Amount available for distribution to holders of Depositary Unitsand the Trust Units evidenced thereby. The Quarterly Distribution Amount isequal to the excess, if any, of (i) the cash that the Trust receives on orbefore the tenth day of the third month after the end of each calendar quarterending before the Trust is dissolved and that is attributable to productionfrom the Net Profits Interest held by the Trust during that calendar quarter,plus, with certain exceptions, any other cash receipts of the Trust during suchquarter, over (ii) the liabilities for the Trust paid during such quarter,subject to adjustments for changes made by the Trustee during such quarter inany cash reserves established for the payment of contingent or futureobligations of the Trust. 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, 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, togetherwith interest earned on such Quarterly Distribution Amount from the date ofreceipt 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 tax purposes in the calendar quarter received by the Trustee,rather than in the quarter distributed by the Trustee. Taxable income of aholder may differ from the Quarterly Distribution Amount because the TreasuryObligations will be treated as generating interest income for tax purposes.There may also be minor variances because of the possibility that, for example,a reserve will be established in one quarter that will not give rise to a taxdeduction until a subsequent quarter, an expenditure paid for in one quarterwill have to be amortized for tax purposes over several quarters. See “FederalIncome Tax Matters”.

Each holder of Depositary Units (including theunderlying Trust Units) of record as of the record date for the final quarterof the Trust’s existence 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.

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**PossibleDivestiture of Depositary Units and Trust Units**

The Trust Agreementimposes no restrictions based on nationality or other status of holders ofTrust Units. However, the Trust Agreement and the Deposit Agreement providethat in the event of certain judicial or administrative proceedings seeking thecancellation or forfeiture of any property in which the Trust has an interestbecause of the nationality, citizenship, or any other status, of any one ormore holders of Trust Units including holders of Depositary Units, the Trusteewill give written notice thereof to each holder whose nationality, citizenshipor other status is an issue in the proceeding, which notice will constitute ademand that such holder dispose of his Depositary Units or withdrawn TrustUnits within 30 days. If any holder fails to dispose of his Depositary Units orwithdrawn Trust Units in accordance with such notice, cash distributions onsuch units are subject to suspension. In the event a holder fails to dispose ofDepositary Units in accordance with such notice, the Depositary may cancel suchholder’s Depositary Units and reissue them in the name of the Trustee,whereupon the Trustee will use its reasonable efforts to sell the DepositaryUnits and remit the net sale proceeds to such holder. In the case of TrustUnits withdrawn from deposit with the Depositary, the Trustee shall redeem suchTrust Units not divested in accordance with such notice, for a cash price equalto the then-current market price of the Depositary Units less the then-currentover-the-counter bid price of the related, withdrawn Treasury Obligations. Theredemption price will be paid out in quarterly installments limited to theamount that otherwise would have been distributed in respect of such redeemedTrust Units.

**Liabilityof Unitholders**

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 a court would give effect tosuch limitation.

**Liquidationof the Trust**

The Trust will be liquidated and the Royalty NPI willbe sold prior to the Liquidation Date, which is expected to occur in 2013.Unitholders of record as of the record date for the final quarter of the Trust’sexistence will be entitled to receive a terminating distribution with respectto each Depositary Unit 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. Underthe Trust Agreement, Eastern American has a right of first refusal to purchasethe Royalty NPI at fair market value, or if applicable the offered third-partyprice, prior to the Liquidation Date.

**FEDERALINCOME TAX MATTERS**

This section is a summary of Federal income taxmatters of general application which addresses the material tax consequences ofthe ownership and sale of Depositary Units. This section provides a generalizedsummary of certain federal income tax matters of general application relatingto ownership and sale of Depositary units by individuals who are citizens orresidents of the United States. Accordingly, the following discussion has onlylimited application to domestic corporations and persons subject to specializedFederal income tax treatment, such as tax-exempt entities (including IRAs), regulatedinvestment companies and insurance companies. The following discussion alsodoes not address tax consequences to foreign persons. It is impractical tocomment on all aspects of Federal laws that may affect the tax consequences ofthe transactions contemplated hereby and of an investment in Depositary Unitsas they relate to the particular circumstances of every prospective Unitholder.Each Unitholder should consult his own tax advisor with respect to hisparticular circumstances including, his alternative minimum tax circumstances.

This summary is based on current provisions of theInternal Revenue Code of 1986, as amended (the “Code”), existing and proposedregulations thereunder and current administrative rulings and court decisions,all of which are subject to changes that may or may not be retroactivelyapplied. Some of the applicable provisions of the Code have not beeninterpreted by the courts or the Internal Revenue Service (“IRS”).

At the time of the issuance of the Depositary Units,Eastern American obtained an opinion of counsel for the benefit of the Trust,based on certain representations and subject to certain qualifications, that,for Federal income tax purposes, (a) the Trust will be taxed as a grantor trustand not as an association taxable as a corporation, (b) the Term NPI will betaxed as a production payment, (c) the income from the Royalty NPI will beroyalty income subject to the allowance for depletion, and (d) a Unitholderwill be eligible to claim Section 29 Credits with respect to certain sales ofgas production attributable to the Royalty NPI. The Trustee has reported theoperations of the Trust consistent with these opinions.

No ruling has been or will be requested from the IRSwith respect to any matter affecting the Trust or Unitholders, and thus noassurance can be provided that the statements set forth herein (which do notbind the IRS or the courts) will not be challenged by the IRS or will besustained by a court if so challenged.

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**Reports**

Unitholders of record are provided informational taxpackages in order to permit computation of their taxable income from ownershipof Depositary Units.

**Treatmentof Depositary Units**

Purchasers of Depositary Units are treated, forFederal income tax purposes, as purchasing directly an interest in the TreasuryObligations and a Trust Unit. Purchasers are therefore required to allocate thepurchase price of their Depositary Unit between the interest in the TreasuryObligations and the Trust Unit in the proportion that the fair market value ofeach bears to the fair market value of the Depositary Unit. Informationregarding purchase price allocations is furnished to Unitholders by theTrustee.

**Classificationand Taxation of the Trust**

For federal income tax purposes, the Trust has beentreated and expects to continue to be treated not as an association taxable asa corporation, but as a grantor trust that is not subject to Federal income taxas an entity separate from its beneficial owners. For tax purposes, Unitholdersare considered to own and receive the Trust’s assets and income as though notrust were in existence. The Trust files an information return, reporting allitems of income, credit or deduction which must be included in the tax returnsof the Unitholders. If the Trust were determined not to be a grantor trust, itis expected that it would be treated either as a partnership subject to thepublicly traded partnership rules under the Code or as an association taxableas a corporation. If the Trust were treated as a publicly traded partnership,it is believed that the Trust’s various items of income and deduction wouldstill be taxable to the Unitholders on a current, flow-through basis aspartners of a partnership and not to the Trust as an association taxable as acorporation. If the Trust were determined to be an association taxable as acorporation, it would be treated as a separate entity subject to corporate taxon its taxable income, Unitholders would be treated as shareholders, anddistributions to Unitholders from the Trust would be treated as nondeductiblecorporate distributions. Such distributions would be taxable to a Unitholder,first, as dividends to the extent of the Unitholder’s pro rata share of theTrust’s earnings and profits, then as a tax-free return of capital to theextent of his basis in his Trust Units, and finally as capital gain to theextent of any excess.

**DirectTaxation of Unitholders**

Assuming that the Trustis treated as a grantor trust for Federal income tax purposes, and Unitholdersare treated for Federal income tax purposes as owning a direct interest in theTreasury Obligations and the assets of the Trust, each Unitholder is taxeddirectly on his pro rata share of the income attributable to the TreasuryObligations and the assets of the Trust and is entitled to claim his pro ratashare of the deductions and credits attributable to the Trust (subject tocertain limitations discussed below). Income, credits and expenses attributableto the assets of the Trust and the Treasury Obligations are taken into accountby Unitholders consistent with their method of accounting and without regard tothe taxable year or accounting method employed by the Trust.

The Trust makes quarterlydistributions to Unitholders of record on each Quarterly Record Date. The termsof the Trust Agreement, as described below, seek to assure to the extentpracticable that taxable income attributable to such distributions will bereported by the Unitholder who receives such distribution, assuming that he isthe 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 allocates income, deductions and credits toUnitholders based on record ownership at Quarterly Record Dates. The IRS couldrequire income and deductions of the Trust to be determined and allocated dailyor require some method of daily proration, which could result in an increase inthe administrative expenses of the Trust.

Based upon future market conditions, forecastedtaxable income may exceed forecasted distributable cash, and the amount of suchexcess could be significant. Such estimates are based on numerous assumptionsas to the allocation of a Unitholder’s purchase price and the amount andtreatment of operating costs, development costs, Trust administrative expenses,production estimates and depletion. No assurance can be given that theestimates will prove to be correct, and the actual relationship betweendistributable cash and taxable income could be materially different.

**Treatmentof Trust Units**

On the assumption that the Trust is a grantor trustfor Federal income tax purposes, each Unitholder is treated as purchasingdirectly an interest in the Net Profits Interests. Purchasers of DepositaryUnits must allocate the portion of their

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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.

**InterestIncome**

The Term NPI is treated as a “production payment”under Section 636(a) of the Code. Thus, Unitholders are treated as making amortgage loan on the Underlying Properties of the Term NPI to Eastern Americanin an amount equal to the amount of the purchase price of each Depositary Unitallocated to the Term NPI. Because it is treated as a debt instrument for taxpurposes, the Term NPI is subject to the original issue discount income (“OID”)rules of the Code which generally require the periodic inclusion of the originalissue discount in income of the purchaser of a debt instrument. The Code alsoauthorizes the IRS to prescribe regulations modifying the statutory provisionswhere, by reason of contingent payments such as those provided for by the TermNPI, the tax treatment provided under the Code provisions does not carry outthe purposes of such provisions.

The IRS has issued a series of proposed and finalregulations dealing with debt instruments which call for contingent payments.The initial set of proposed regulations dealing with this topic were issued onApril 8, 1986, and modified on February 26, 1991 (the “Old Proposed Regulations”).A second set of proposed contingent payment regulations were issued on January19, 1993, but were withdrawn prior to publication in the Federal Register. OnDecember 15, 1994, the IRS replaced the Old Proposed Regulations by issuing athird set of proposed regulations addressing debt obligations that provide forcontingent payments (the “New Proposed Regulations”). The New ProposedRegulations were proposed to be effective for debt obligations issued on orafter the date that is sixty days following the promulgation of the NewProposed Regulations in final form. In this regard, the New ProposedRegulations have been adopted in final form (the “Final Regulations”), thougheffective only for debt instruments issued after August 12, 1996. Thus, bytheir terms, the New Proposed Regulations and the Final Regulations do notapply to the Term NPI. However, the Preamble to the Final Regulations providesthat for debt instruments issued prior to the effective date of the FinalRegulations, a taxpayer may use any reasonable method to account for such debtinstruments, including a method that would have been permitted under theproposed regulations when the debt instrument was issued.

The Trustee understands that, in accordance with theforegoing, Eastern American, as obligor under the Term NPI, intends to continueto treat the Term NPI in the manner provided under the Old Proposed Regulations,which were proposed at the time the Term NPI was transferred to the Trust andTrust Units were issued. Under this approach, each payment (at the time theamount of such payment becomes fixed) made to the Trust with respect to theTerm NPI will be treated first as a payment of interest to the extent ofinterest deemed accrued under the OID rules and the excess (if any) will betreated as a payment of principal. The total amount treated as principal willbe limited to a portion of the purchase price of each Depositary Unit allocatedto the Term NPI. For purposes of determining the amount of accrued interest,the Old Proposed Regulations required the use of the Applicable Federal Ratebased on the due date of the final payment due under the terms of the productionpayment, which for the Term NPI is May 15, 2013.

Unitholders are also required to recognize and reportOID interest income attributable to the Treasury Obligations. In general, thetotal amount of OID a Unitholder is required to recognize will be calculated asthe difference between the amount of the purchase price of a Depositary Unitallocated to the Treasury Obligations and the pro rata portion of the faceamount of such Treasury Obligations attributable to the Depositary Unit. Theamount of OID so calculated is included in income by a Unitholder on the basisof a constant interest rate computation.

**RoyaltyIncome and Depletion**

The income from the Royalty NPI is royalty incomesubject to an allowance for depletion. The depletion allowance must be computedseparately by each Unitholder for each oil or gas property (within the meaningof Code Section 614). The IRS presently takes the position that a net profitsinterest burdening multiple properties is one property for depletion purposes.Accordingly, the tax information reports that the Trust provides to Unitholdersand the IRS have reported all production attributable to the Royalty NPI asproduction attributable to a single property for depletion purposes. Suchreporting treatment is expected to continue until at least the IRS position onsuch treatment is changed.

The allowance for depletion with respect to a propertyis determined annually and is the greater of cost depletion or, if allowable,percentage depletion. Percentage depletion is generally available to “independentproducers” (generally persons who are not substantial refiners or retailers ofoil or gas or their primary products) on the equivalent of 1,000 barrels ofproduction per day. Percentage depletion is a statutory allowance equal to 15%of the gross income from production from a property which is included in incomeby a taxpayer.

Percentage depletion is subject to a net incomelimitation which is 100% of the taxable income from the property, computedwithout regard to depletion deductions and certain loss carrybacks. A taxpayer’stotal percentage depletion

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deductionfor all properties for a taxable year is limited to 65% of the taxpayer’staxable income for the year, before percentage depletion and certain otherdeductions. Unlike cost depletion, percentage depletion is not limited to theadjusted tax basis of the property, although it reduces that adjusted tax basis(but not below zero).

In computing cost depletion for each property for anyyear, the adjusted tax basis of that property at the end of that year isdivided by the estimated total units (Mcf of gas) recoverable from thatproperty to determine the per-unit allowance for such property. The per-unitallowance is then multiplied by the number of units produced and sold from thatproperty during the year. Cost depletion for a property cannot exceed theadjusted tax basis of such property. While the Trust is treated as a grantortrust for Federal income tax purposes, each Unitholder computes cost depletionby using as his basis for the property the portion of his cost basis for hisDepositary Units that is allocated first to the NPI and second to the RoyaltyNPI. Information is provided by the Trustee to each Unitholder reflecting howthat basis should be allocated.

**Section29 Credit**

The Trustee has been informed by Eastern American thatmost of the production attributable to the Royalty NPI is gas produced fromDevonian shale or a tight formation. Provided a number of requirements are met,taxpayers are entitled to the Section 29 Credit for gas produced from Devonianshale or a tight formation. The Section 29 Credit generally applies only to gasproduced from Devonian shale or a tight formation in the United States and soldto an unrelated party prior to January 1, 2003, from wells drilled afterDecember 31, 1979, and prior to January 1, 1993. Additionally, the Section 29Credit applies only to gas produced from a tight formation which, as ofApril 20, 1977, was committed or dedicated to interstate commerce (asdefined in Section 2(18) of the Natural Gas Policy Act, as in effect onNovember 5, 1990), or which is produced from a well drilled after November 5,1990. A Unitholder is eligible to claim the Section 29 Credit with respect tocertain sales of such gas attributable to the Royalty NPI. Under current law,the Section 29 credit is no longer available for production after December 31,2002.

Section 29 Credits resulting from an investment inDepositary Units may only be used to reduce a taxpayer’s regular income taxliability and generally may not be used to reduce a taxpayer’s liability foralternative minimum tax. Section 29 Credits available to a taxpayer in anytaxable year may not be carried back but may be carried forward for use by thattaxpayer in a subsequent tax year only in a limited fashion. See “AlternativeMinimum Tax” below.

The Section 29 Credit is not available for productionafter December 31, 2002. Congress in past years has considered, withoutenacting, legislation to extend energy tax credits such as the Section 29Credit beyond their expiration date or to create new similar credits. Thepotential effect that enactment of any such possible legislation may have onUnitholders in the future is unknown.

OnMarch 23, 1999, the United States Tax Court of Appeals for the Tenth Circuitaffirmed a lower court decision in *True Oil Company v.*C.I.R.170 F.3d 1294. The Court ruled that, in order to be eligible for creditsunder Section 29 of the Internal Revenue Code, each well from which gas isproduced from Devonian shale or a tight formation must receive a determinationfrom the Federal Energy Regulatory Commission (“FERC”) that the gas producedis, in fact, produced from Devonian shale or a tight formation. EasternAmerican has verified that most producing gas wells subject to the Royalty NPIhave received a well category determination from FERC. Should the InternalRevenue Service challenge the amount of the Trust’s production qualifying forSection 29 Credits, a Unitholder might not be able to claim the benefit ofSection 29 credits for production attributable to a well that did notreceive a FERC determination. If successful, such a challenge could affect thetax reporting for such credits for tax years examined by the IRS and anysubsequent tax years. However, it should be noted that under current law theSection 29 credit is no longer available for production after December 31,2002.

**OtherIncome and Expenses**

From time to time, the Trust may generate interestincome on funds held as a reserve or held until the next distribution date.Expenses of the Trust include administrative expenses of the Trustee. Under theCode, certain miscellaneous itemized deductions of an individual taxpayer aredeductible only to the extent that in the aggregate they exceed 2% of thetaxpayer’s adjusted gross income. Certain administrative expenses attributableto the Trust Units may have to be aggregated with an individual Unitholder’sother miscellaneous itemized deductions to determine the excess over 2% ofadjusted gross income. To date, the amount of such expenses has not beensignificant in relation to the Trust’s income.

**AlternativeMinimum 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 generally entitled to a credit against,or reduction in, his regular tax liability in a subsequent year in an

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amountequal to the AMT he pays for a prior taxable year. However, that credit canonly be used to reduce his regular tax liability for that subsequent year tothe extent his regular tax liability for that subsequent year exceeds histentative minimum tax liability for that subsequent year.

The Section 29 Credit allowable to a taxpayer as areduction of his tax liability for any prior taxable year could not haveexceeded the excess of his regular tax liability for such taxable year, asreduced by his foreign tax credits and certain nonrefundable credits, over histentative minimum tax liability for that year. Any amount of Section 29 Creditdisallowed for the prior tax year solely because of this limitation willincrease a taxpayer’s credit for the prior year’s AMT, as described above.There is no provision for the carryback or carryforward of the Section 29Credit in any other circumstances. Therefore, a Unitholder may not havereceived the full benefit of available Section 29 Credits, depending on hisparticular AMT circumstances. However, it should be noted that under currentlaw the Section 29 credit is no longer available for production after December31, 2002.

Since the effect of the AMT varies depending upon eachUnitholder’s personal tax and financial position, each Unitholder is advised toconsult with his, her or its own tax advisor concerning the effect of the AMTand Section 29 Credits attributable to an investment in the Depositary Units.

**Non-PassiveActivity**

The income, credits and expenses of the Trust are nottaken into account in computing the passive activity losses and income underCode Section 469 for a Unitholder who acquires and holds Depositary Units as aninvestment and did not acquire them in the ordinary course of business.

**UnrelatedBusiness Taxable Income**

Certain organizations that are generally exempt fromtax under Code Section 501 are subject to tax on certain types of businessincome defined in Code Section 512 as unrelated business income. The income ofthe Trust is not unrelated business taxable income within the meaning of CodeSection 512 so long as the Trust Units are not “debt-financed property” withinthe meaning of Code Section 524(b). In general, a Trust Unit would bedebt-financed if the Unitholder incurs debt to acquire a Trust Unit orotherwise incurs or maintains a debt that would not have been incurred ormaintained if such Trust Unit had not been acquired. Legislative proposals havebeen made from time to time which, if adopted, would result in the treatment ofincome attributable to the Royalty NPI as unrelated business income.

**Sale ofDepositary Units; Sale of Trust Units or Treasury Obligations**

Generally, a Unitholder will realize gain or loss onthe sale or exchange of his Depositary Units measured by the difference betweenthe amount realized on the sale or exchange and his adjusted basis for suchDepositary Units. Gain or loss on the sale of Depositary Units by a Unitholderwho is not a dealer with respect to such Depositary Units and who has a holdingperiod for the Depositary Units of more than one year will be treated aslong-term capital gain or loss, except to the extent of the depletion recaptureamount and any accrued market discount as explained below. A Unitholder’sinitial basis in his Depositary Units is equal to the amount paid for suchDepositary Units. Such basis is increased by the amount of OID incomerecognized by the Unitholder attributable to the Treasury Obligations. Suchbasis is reduced by deductions for depletion claimed by the Unitholder (but notbelow zero). In addition, such basis is reduced by the amount of any paymentsattributable to the Term NPI which are treated as payments of principal underthe OID rules.

For Federal income tax purposes, the sale of aDepositary Unit is treated as a sale by the Unitholder of his interest in theTreasury Obligations and the assets of the Trust. Thus, upon the sale ofDepositary Units, a Unitholder must treat as ordinary income his depletion recaptureamount, which is an amount equal to the lesser of (i) the gain on that saleattributable to disposition of the Royalty NPI or (ii) the sum of the priordepletion deductions taken with respect to the Royalty NPI (but not in excessof the initial basis of such Depositary Units allocated to the Royalty NPI). Itis possible that the IRS would take the position that a portion of the salesproceeds is ordinary income to the extent of any accrued income at the time ofsale allocable to the Depositary Units sold, but which is not distributed tothe selling Unitholder.

A Unitholder who allocates his purchase price (or isrequired to allocate his purchase price) to the Treasury Obligations in anamount less than the sum of (a) his share of the initial issue price of theTreasury Obligations and (b) his share of OID income recognized by priorholders of the Treasury Obligations (any such difference represents “marketdiscount”) will generally be required to recognize ordinary income to theextent of any accrued market discount upon sale of the Depositary Units. Ingeneral, accrued market discount is an amount which bears the same ratio tototal market discount as the number of days which a Unitholder holds aDepositary Unit bears to the number of days after the date the Unitholderacquired the Depositary Unit and up to and including the Liquidation Date.

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**Withdrawalof Trust Units or Treasury Obligations**

A Unitholder will recognize no gain or loss upon thewithdrawal of the Trust Units or Treasury Obligations from the Depositary. Asale of the Trust Units or the Treasury Obligations will result in therecognition of income or loss.

**Sale ofNet Profits Interests or Production Payment**

A sale by the Trust of Net Profits Interests aretreated for Federal income tax purposes as a sale of Net Profits Interests by aUnitholder. Thus, a Unitholder will recognize gain or loss on a sale of NetProfits Interests by the Trust. A portion of that income may be treated asordinary income to the extent of depletion recapture. Receipt by the Trust ofproceeds drawn from the letter of credit supporting Eastern Marketing’sobligations under the Gas Purchase Contract is, in certain cases, inconsideration for the conveyance to Eastern Marketing of a production paymentinterest in reserves attributable to the Net Profits Interests or to compensatethe Trust for damages from a breach of the Gas Purchase Contract. All or aportion of such proceeds may be treated as non-taxable loan proceedsattributable to a loan by Eastern Marketing resulting from the productionpayment, may be treated as ordinary income not subject to depletion or mayreceive some other treatment, depending upon facts existing at that time. Tothe extent receipt of such proceeds is attributable to a sale of reserves by theTrust, depletion and Section 29 Credits available to the Unitholders forsubsequent periods is reduced.

**BackupWithholding**

In general, distributions of Trust income are notsubject to “backup withholding” unless (i) the Unitholder is an individual orother noncorporate taxpayer and (ii) such Unitholder fails to comply withcertain reporting procedures.

**TaxShelter Registration**

The Trust has been registered with the IRS as a “taxshelter,” and has received tax shelter registration number 93040000163. A “taxshelter,” for purposes of the registration requirement, is an investment withrespect to which a person could reasonably infer, from the representations madein connection with any offer for sale of any interest in the investment, thatthe “tax shelter ratio” for any investor may be greater than two to one as ofthe close of any of the first five years ending after the date on which theinvestment is offered for sale. The term “tax shelter ratio” with respect to aninvestment means the ratio that the aggregate amount of gross deductions forany investor, determined without regard to income derived from the investment,plus 350% of the credits that are potentially available to an investor, bearsto the investment base for the year. The “investment base” is equal to thecash, plus the adjusted basis (which may be less than the fair market value) ofany other property invested. Certain borrowings, however, including those fromother participants in the venture, are excluded from the investment base. WhileEastern American has no knowledge of any such borrowings, it is possible that,due to such borrowings, the investment base of an investor would besubstantially reduced or eliminated.

A Unitholder who sells or otherwise transfers a TrustUnit must furnish to the transferee the tax shelter registration number setforth above. The penalty for failure of the transferor of a Trust Unit tofurnish such tax shelter registration number to a transferee is $100 for eachsuch failure. Unitholders must disclose the tax shelter registration number ofthe Trust on Form 8271 to be attached to the tax return on which any deduction,loss, credit or other benefit generated by the Trust is claimed or income ofthe Trust is included. A Unitholder who fails to disclose the tax shelterregistration number on his return, without reasonable cause for such failure,will be subject to a $250 penalty for each such failure. (Any penaltiesdiscussed herein are not deductible for income tax purposes.)

**ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOESNOT INDICATE THIS INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED,EXAMINED OR APPROVED BY THE IRS.**

**STATE TAXCONSIDERATIONS**

The following is intended as a brief summary ofcertain information regarding state income taxes and other state tax mattersaffecting individual Unitholders. Unitholders are urged to consult their ownlegal and tax advisors with respect to these matters.

The Trust owns the Net Profits Interests burdening theUnderlying Properties located in the states of Pennsylvania and West Virginia.Both of these states have income taxes applicable to individuals and mayrequire the Trust to withhold taxes from distributions made to nonresidentUnitholders. Withholding, if required, is at the rate of 4% of taxable incomeattributable to West Virginia and 3.07% of taxable income attributable toPennsylvania. A Unitholder may be required to file state income tax returnsand/or to pay taxes in these states and may be subject to penalties for failureto comply with such requirements. Generally, Unitholders may treat state incometaxes that the Trust has withheld as having been paid by them to the state forwhich they were withheld. Unitholders may be able to treat any taxes that theyhave paid or that have been withheld and paid to West Virginia or Pennsylvaniaas a deduction in computing Federal income tax, or as a credit or a

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deductionin computing another state’s income tax.

Unitholders receive information concerning theDepositary Units and the Trust Units sufficient to identify the income fromDepositary Units that is allocable to each state. Holders of Depositary Unitsshould consult their own tax advisors to determine their income tax filingrequirements with respect to their share of income of the Trust allocable tostates imposing a tax on such income.

The Trust Units and therefore also the DepositaryUnits may constitute real property or an interest in real property under thetax, inheritance, estate and probate laws of either or both of Pennsylvania andWest Virginia. If the Depositary Units are held to be real property or aninterest in real property under the laws of a state in which the UnderlyingProperties are located, the holders of Depositary Units may be subject to advalorem or other property tax, devolution, probate and administration laws, andinheritance or estate and similar taxes, under the laws of such state.

**AvailableInformation**

The Trust does not maintain an internet address or awebsite, and therefore does not make copies of its reports under the ExchangeAct available in that manner. The Trust’s filings under the Exchange Act areavailable electronically from the website maintained by the Securities andExchange Commission at http://www.sec.gov. The Trust will also provideelectronic copies of its recent filings free of charge upon request to theTrustee, and will provide paper copies of its recent filings for its costs ofreproduction upon request to the Trustee.

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

Followingis a summary of the principal risks associated with an investment in Units inthe Trust.

**Naturalgas prices fluctuate due to a number of factors, and lower prices will reducenet proceeds to the Trust and distributions to Unitholders**.

TheTrust’s revenues and distributions to Unitholders are highly dependent on thesales prices as reflected in the Henry Hub Average Price, as defined in the GasPurchase Contract, and on the quantities of natural gas attributable to the NetProfits Interests. Prices for natural gas can fluctuate widely in response to anumber of factors that are beyond the control of Eastern American and theTrust. These factors include:

worldwide economicconditions;

weather conditions;

changes and expectationsregarding natural gas production and transportation;

levels of actual andanticipated demand;

price and availability ofalternative fuels;

the availability of  gathering, transportation and processingfacilities; and

theeffects of worldwide energy conservation measures.

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**Low gasprices may reduce production**.

Lownatural gas prices may reduce the amount of gas that is economic to produce. Asa result, the operator could determine during periods of low gas prices to shutin or curtail production. In addition, the operator could determine duringperiods of low gas prices to plug and abandon marginal wells.

**Estimatedreserves and future production levels are uncertain.**

Thevalue of the Depositary Units depends on, among other things, the provedreserves and production levels attributable to the Net Profits Interests. Thereare many uncertainties involved in estimating quantities and values of provedreserves and in projecting future rates of production. The reserve dataincluded in this Annual Report are estimates only, and actual quantities andvalues of natural gas are likely to differ from the estimated amounts. Thediscounted present values shown for the Net Profits Interests were preparedusing guidelines established by the SEC for disclosure of reserves and shouldnot be considered representative of market value.

**There arerisks inherent in the development and production of natural gas.**

Distributionsto Unitholders could be adversely affected if any of the risks typicallyassociated with the development, production and transportation of natural gaswere to occur, including personal injuries, property damage, well damage anddamage to productive formations or equipment.

**None ofthe Trust, the Trustee nor the Unitholders has any control over the operationof the properties.**

Noneof the Trust, Trustee nor the Unitholders is able to influence or control theoperation of the properties. All of the wells are operated by Eastern American.As operator, Eastern American has the right to abandon or sell any well if, inits opinion, the well or property ceases to produce or is not capable ofproducing in commercially paying quantities. In general, upon abandonment ofany well to which the Net Profits Interests relate, that portion of the NetProfits Interests will be extinguished.

**Gas reservesare depleting assets.**

Gasreserves are depleting assets. The reserves attributable to the Net ProfitsInterests have declined and are expected to continue to decline over time. Theaccreting value of the Treasury Obligations may not fully offset the depletionof the reserves attributable to the Net Profits Interests.

**Compliancewith government regulation may be expensive.**

Theproduction, transportation and sale of natural gas from the wells to which theNet Profits Interest relate are subject to governmental regulation. Compliancewith these regulations may be expensive.

**Operatingcosts, capital expenditures and taxes reduce payments to the Trust.**

Theoperating costs charged in calculating Net Proceeds include a fixed charge,subject to increase of up to 5% annually. In addition, property and productiontaxes and certain capital expenditures are deducted from gross proceeds indetermining the Net Proceeds. In general, increases in chargeable costs willhave the effect of reducing the amount of Net Proceeds.

**Increasedadministrative costs reduce distributions to Unitholders.**

Administrativecosts, including professional services fees and expenses, are deducted prior todistributions to Unitholders. Consequently, increases in administrative costsadversely affect distributions to Unitholders.

**Externalevents may result in additional increased administrative costs.**

Asdescribed elsewhere in this Annual Report on Form 10-K, in November 2005Ensource Energy Income Fund LP commenced an unsolicited exchange offer in aneffort to acquire control of the Trust. The Trust incurred substantiallyincreased administrative costs as a result of the Ensource exchange offer. Thecosts incurred by the Trust in connection with the Ensource offer decreaseddistributions to Unitholders.  Ensourceterminated its unsolicited offer to acquire control of the Trust as ofSeptember 15, 2006; however, other similar offers or other types of externalevents could result in additional increased costs.

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**The legalstatus of the Net Profits Interests under some circumstances is unclear.**

At thetime of the formation of the Trust, Eastern American noted that it was likelythat the Net Profits Interests would not be treated as real property interestsunder the laws of West Virginia and Pennsylvania. Nevertheless, EasternAmerican recorded the Conveyances in the real property records of West Virginiaand Pennsylvania in accordance with local recording acts. Eastern Americanbelieves that, if, during the term of the Trust, Eastern American becomes involvedas a debtor in a bankruptcy proceeding under the Federal Bankruptcy Code, theNet Profits Interests relating to the Underlying Properties located in WestVirginia would be treated as fully conveyed personal property interests.However, if the Conveyances were held to constitute executory contracts, and ifsuch contracts were not to be assumed in a bankruptcy proceeding, the Trustprobably would be treated as an unsecured creditor of Eastern American. Withrespect to the properties located in Pennsylvania, which representedapproximately 10% of the reserves attributable to the Net Profits Interests atthe inception of the Trust, Eastern American believed that there is a greaterrisk that the Net Profits Interests would not be treated as fully conveyedproperty interests and instead the Conveyances could be treated as executorycontracts, meaning that the Trust could be treated as an unsecured creditorwith respect to those interests.

**The NetProfits Interests are subject to any defects in Eastern American’s rights tothe Underlying Properties.**

TheNet Profits Interests are subject to any defects in Eastern American’s rightswith respect to the Underlying Properties. Eastern American believes that itsinterests with respect to the Underlying Properties are good and defensible inaccordance with standards generally accepted in the Appalachian oil and gasindustry, subject to exceptions which do not detract substantially from thevalue of its interests. However, it is possible that leases or farmout agreementscould be treated as executory contracts if the third party lessor or farmorunder a farmout agreement were to become a debtor in bankruptcy, meaning thatit is possible that a lease or farmout agreement could be rejected in abankruptcy proceeding.

**Theopinion of tax counsel obtained at inception of the Trust is not binding on theIRS or any court.**

At theinception of the Trust, Eastern American received an opinion of counsel thatthe Trust is a grantor trust and not an association taxable as a corporationfor Federal income tax purposes, and that each Unitholder would be taxeddirectly on his pro rata share of the income attributable to assets of theTrust and, subject to certain limitations, would be entitled to claim depletiondeductions and tax credits attributable to the Royalty NPI and would beentitled to claim his pro rata share of other deductions attributable to assetsof the Trust. However, the opinion of counsel is not binding on the IRS or anycourt.

**Taxableincome could exceed cash distributions.**

It ispossible that taxable income per Depositary Unit may exceed cash distributionsper Depositary Unit. In addition, to the extent that distributable cash is usedto establish Trust reserves or to repay borrowed funds, Unitholders willrecognize taxable income without receiving the cash used to establish reservesor to repay borrowed funds.

**EasternAmerican and the Trust may have conflicts of interest.**

Theinterests of Eastern American and the interests of the Trust and theUnitholders may at times be different. For example, Eastern American’sinterests may conflict with those of the Trust and Unitholders in situationsinvolving the development, operation or abandonment of the UnderlyingProperties or adjacent properties. In making decisions with respect to suchoperations, 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.

Inaddition, Eastern American’s interests may conflict with those of the Trust andthe Unitholders in situations involving the sale of Underlying Properties.Eastern American has the right to sell all or any portion of the UnderlyingProperties without restrictions; however, except in limited circumstances whereEastern American may require the Trust to release the Net Profits Interests,the Conveyances provide that the purchaser of any of the Underlying Propertieswill acquire such Underlying Properties subject to the Net Profits Interests.The Conveyances provide that a purchaser will be subject to the same standards ofconduct with respect to development, operation and abandonment of suchUnderlying Properties as are

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applicable toEastern American. Eastern American has the right, subject to limitations, tocause the Trust to release a portion of the Net Profits Interests in connectionwith a sale of a portion of the Underlying Properties.

**Unitholdershave only limited voting rights.**

WhileUnitholders have certain voting rights pursuant to the terms of the TrustAgreement, these rights are more limited than those of stockholders of mostcorporations. For example, there is no requirement for annual meetings ofUnitholders or for an annual or other periodic re-election of the Trustee.

**Unitholders could be subject tounlimited liability.**

Consistentwith Delaware law, the Trust Agreement provides that the Unitholders will havethe same limitation on liability as is accorded under the laws of such state tostockholders of a corporation for profit. No assurance can be given, however,that the courts in jurisdictions outside of Delaware will give effect to suchlimitation.

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

EasternAmerican is a privately held, independent energy company engaged primarily inthe exploration, development, production, transportation and marketing ofnatural gas within the Appalachian Basin. The ability of Eastern Marketing andEastern American to perform their obligations under the Gas Purchase Contractdepends on their financial condition, which in turn depends upon the supply anddemand for natural gas, economic conditions and upon financial, business andother factors, many of which are beyond the control of Eastern American.

**None of the Trustee, the Trust northe Unitholders has any control over the operation of the UnderlyingProperties.**

None of theTrustee, the Trust nor the Unitholders has any influence or control over theoperation of the Underlying Properties, all of which are operated by EasternAmerican.

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

None.

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

Reference is madeto Item 1 of this Form 10-K.

**Item 3.****   *****LegalProceedings****.*

None.

**Item 4.****   *Submission of Matters to a Vote of Unitholders****.*

None.

**PART II**

**Item 5.****    *Market for Registrant’s Common Equity, Related Unitholders Matters andIssuer Purchases of Equity Securities.***

The Depositary Units are traded on the New York StockExchange under the ticker symbol “NGT.” The high and low prices anddistributions paid during the quarters in the two-year period ended December31, 2006 were as follows:
| Quarter                        | ** ** | **High** | ** ** | **Low** | ** ** | **Distributions  Paid** | ** ** |
|--------------------------------|------------|----------|------------|---------|------------|-------------------------|------------|
| 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 |   |
|                           |       |     |       |    |       |                    |       |
| 2006:                          |       |     |       |    |       |                    |       |
| First (to March  31, 2006)     |       | $        | 28.65      |    | $          | 26.71                   |       | $ | 0.74 |   |
| Second (to June  30, 2006)     |       | $        | 29.64      |    | $          | 27.00                   |       | $ | 0.64 |   |
| Third (to  September 30, 2006) |       | $        | 30.75      |    | $          | 25.20                   |       | $ | 0.65 |   |
| Fourth (to December 31,  2006) |       | $        | 28.80      |    | $          | 25.22                   |       | $ | 0.45 |   |

 

At March 13, 2007, the 5,900,000 Depositary Unitsoutstanding were held by approximately 221 Unitholders of record.

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With respect to the Treasury Obligations, the high andlow closing prices per $1,000 face amount for the period from January 1, 2006to December 31, 2006 were $755.85 and $698.78, respectively. The closing priceon December 31, 2006 was $745.06 per $1,000 face amount.

During the fourth quarter of2006, there were no purchases of Units made by or on behalf of the Trust or any“affiliated purchaser” as defined in Rule 10b-18 (a) (3) under the Exchange Act.

The following graph shows a comparison of cumulativetotal unitholder return, calculated on a distributions reinvested basis, fromDecember 31, 2001 through December 29, 2006 for the Trust, a peer group indexconsisting of Hugoton Royalty Trust, LL&E Royalty Trust and Torch EnergyRoyalty Trust, and a broad New York Stock Exchange market index.  The graph assumes that $100 was invested inthe Trust's units and the above indices on December 31, 2001. Historic priceperformance is not necessarily indicative of future price performance.

COMPARE 5-YEAR CUMULATIVE TOTAL RETURNAMONG EASTERN AMERICAN NATURAL GAS TRUSTNYSE MARKET INDEX AND PEER GROUP INDEX

ASSUMES $100 INVESTED ON  DEC. 31, 2001ASSUMES  DIVIDEND REINVESTEDFISCAL YEAR ENDING  DEC. 31, 2006

**Item 6.****    *Selected Financial Data.***
| ** **                     | ** ** | **Year Ended** | ** ** |
|--------------------------------|------------|---------------------|------------|
| ** **                     | ** ** | **December**        | ** ** | **December** | ** ** | **December** | ** ** | **December** | ** ** | **December** | ** ** |
| ** **                     | ** ** | **31, 2006**   | ** ** | **31, 2005** | ** ** | **31, 2004** | ** ** | **31, 2003** | ** ** | **31, 2002** | ** ** |
| Royalty Income                 |       | $                   | 17,663,792 |   | $ | 18,179,459 |   | $ | 14,449,208 |   | $ | 13,177,510 |   | $ | 9,024,646 |   |
| Distributable  Income          |       | $                   | 14,158,872 |   | $ | 14,597,387 |   | $ | 12,019,847 |   | $ | 10,947,816 |   | $ | 7,808,725 |   |
| Distribution  Amount           |       | $                   | 14,658,872 |   | $ | 13,712,387 |   | $ | 11,919,847 |   | $ | 10,732,816 |   | $ | 7,808,725 |   |
|                           |       |                |       |   |   |   |   |   |   |   |   |
| Distributable  Income per unit |       | $                   | 2.40       |   | $ | 2.47 |   | $ | 2.04 |   | $ | 1.86 |   | $ | 1.32 |   |
| Distribution  Amount per unit  |       | $                   | 2.48       |   | $ | 2.32 |   | $ | 2.02 |   | $ | 1.82 |   | $ | 1.32 |   |
|                           |       |                |       |   |   |   |   |   |   |   |   |
| Total assets at year  end      |       | $                   | 28,165,747 |   | $ | 32,954,834 |   | $ | 35,000,087 |   | $ | 37,436,640 |   | $ | 41,006,654 |   |

 

**Item 7.****    *Management’s Discussion and Analysis of Financial Condition and Resultsof Operation****.*

**General**

The Trust does not conduct any operations oractivities. The Trust’s purpose is, in general, to hold the Net ProfitsInterests, to distribute to Unitholders cash which the Trust receives inrespect of the Net Profits Interests and to perform certain administrativefunctions in respect of the Net Profits Interests and the Depositary Units. TheTrust derives substantially all of its income and cash flows from the NetProfits Interests.

22

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Under the Gas Purchase Contract, Eastern Marketingpurchases gas from the Trust at a variable price for any quarter equal to theHenry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu,multiplied by 110% to effect a fixed adjustment for Btu content. The Henry HubAverage Spot Price is defined as the price per MMBtu determined for anycalendar quarter equal to the price obtained with respect to each of the threemonths in such quarter, in the manner specified below, and then taking theaverage of the prices determined for each of such three months. The pricedetermined for any month of such quarter is equal to the average of (i) thefinal settlement price per MMBtu for Henry Hub Gas Futures Contracts (asdefined), 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 closingsettlement price per MMBtu of Henry Hub Gas Futures Contracts determined as ofthe contract settlement date for such month, as reported in *The Wall Street Journal*, for such contracts which expire ineach of the six months following such month. A Henry Hub Gas Futures Contractis defined as a gas futures contract for gas to be delivered to the Henry Hubwhich is traded on the New York Mercantile Exchange.

Accordingly, the pricepayable to the Trust for production may vary based on fluctuations in naturalgas futures prices during the relevant calculation period. The price payable tothe Trust will have a direct impact, positively or negatively, on the quarterlydistributions payable by the Trust to the Unitholders.

During 2004, an oil and gas company contacted EasternAmerican and inquired as to whether it would sell certain assets situated inCentre County, Pennsylvania including the Horne #1, Horne #2 and Horne #15wells (the Horne Underlying Properties), which are wells in which the Trustowned a Net Profits Interests. Eastern American reviewed the Trust Agreementand certified to the Trustee that:  (i)the gross purchase price to be received by Eastern American for the sale of theHorne Underlying Properties in a single transaction or a series of relatedtransactions was less than $500,000; (ii) the Assignee of the Horne UnderlyingProperties was not an Affiliate of Eastern American; (iii) the aggregate saleproceeds of $80,205 to be received by the Trust from Eastern American (theTrust’s Horne Sale Proceeds) represented the fair value to the Trust for NetProfits Interests to be released by the Trustee in connection with EasternAmerican’s sale of the Horne Underlying Properties; and (iv) the Trust’s HorneSale Proceeds plus the aggregate sale proceeds received by the Trust pursuantto Section 3.02(b)(ii) of the Trust Agreement with respect to all other NetProfits Interests previously released by the Trustee pursuant to Section3.02(b) during the most recently completed twelve calendar months did notexceed $500,000. Eastern American advised the oil and gas company that it couldsell these wells. The Trust’s share of the proceeds of $80,205 was included inthe Distributable Income of the Trust during the year ended December 31, 2004.

Also, during 2004, a landowner contacted EasternAmerican to inquire about the sale of certain wells located on the landowner’sproperty, including the Wurst #2 well, which is a well in which the Trust owns aNet Profits Interest. Eastern certified to the Trust that (i) the Assignee ofthe Wurst #2 was not an Affiliate of Eastern, and (ii) the aggregate saleproceeds to be received from all other sales of wells in which the Trust owneda Net Profits Interest and previously released by the Trust during thepreceeding twelve (12) calendar months did not exceed $500,000. The Wurst #2well was found to be uneconomic to operate and was subject to plugging andabandonment by Eastern American if not assigned to the landowner. EasternAmerican advised the landowner that it could assign this well. The Wurst #2well had no value and no cash distribution was made to the Trust.

Over the remaining life of the Trust, additional wellsmay need to be disposed of for similar or other reasons.

The Trust is responsiblefor paying the Trustee’s fees and all legal, accounting, engineering and stockexchange fees, printing costs and other administrative expenses incurred by orat the direction of the Trustee. The total of all Trustee fees and Trustadministrative expenses for 2006 was $1,317,881 including the Trustee’s fee of$108,000. In addition to such expenses, in 2006, the Trust paid EasternAmerican an overhead reimbursement of $328,432. The overhead reimbursementincreases by 3.5% per year and is payable quarterly.

On December 8, 2004, the Trust announced approval bythe Trust Unitholders of a proposal to elect JPMorgan Chase to serve assuccessor trustee of the Trust upon the effective date of the resignation ofThe Bank of New York as trustee of and depositary for the Trust and to amendthe Trust Agreement to change the compensation of the Trustee. The resignationof The Bank of New York took effect on January 1, 2005. As successor trustee,JPMorgan Chase received annual compensation of $108,000 plus fees andexpenses.  Effective October 2, 2006, TheBank of New York Trust Company, N.A. acquired the corporate trust business ofJPMorgan Chase Bank, N.A.  Consequently,The Bank of New York Trust Company, N.A., currently serves as Trustee of theTrust.  The Trustee’s annual compensationdid not change as a result of the October 2, 2006 acquisition by The Bank ofNew York Trust Company, N.A. of the corporate trust business of JPMorgan Chase.

During the last two quarters of 2005 and during 2006,the Trust incurred substantially increased fees for professional servicesrelating to the exchange offers made by Ensource Energy Income Fund LP during2005 and 2006. Expenses relating

23

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to theEnsource exchange offers incurred by the Trust during 2005 totaledapproximately $725,798, including $418,639 for fees and expenses the Trust paidto a financial advisory firm in connection with its analysis of the Ensourceexchange offers.  Expenses relating tothe Ensource exchange offers incurred by the Trust during 2006 totaledapproximately $701,606, including $387,923 for fees and expenses the Trust paidto a financial advisory firm in connection with its analysis of the Ensourceexchange offers.

The costs the Trustincurs in the future will fluctuate depending primarily on the expenses theTrust incurs for professional services, particularly legal, accounting andengineering services.

**Critical Accounting Policies**

Thefollowing is a summary of the critical accounting policies followed by theTrust.

*Basis ofAccounting:*

The financial statements of the Trust differ fromfinancial statements prepared in accordance with accounting principlesgenerally accepted in the United States of America due to the following: (i)certain cash reserves may be established for contingencies which were notaccrued in the financial statements; (ii) amortization of the Net ProfitsInterests in gas properties is charged directly to Trust Corpus; and (iii) thesale of the Net Profits Interests is reflected in the Statements of DistributableIncome as cash proceeds to the Trust.

*NetProfits Interests in Gas Properties:*

The Net Profits Interests in gas properties areperiodically assessed to determine whether their net capitalized cost isimpaired. The Trust will determine if a writedown is necessary to itsinvestment in the Net Profits Interests in gas properties to the extent thattotal capitalized costs, less accumulated amortization, exceed undiscountedfuture net revenues attributable to proved gas reserves of the Underlying Properties.The Trust will then provide a writedown to the extent that the net capitalizedcosts exceed the discounted future net revenues attributable to proved gasreserves of the Underlying Properties. Any such writedown would not reducedistributable income, although it would reduce Trust Corpus.

Amortization of the Net Profits Interests in gasproperties is calculated on a units-of-production basis, whereby the Trust’scost basis in the properties is divided by total Trust proved reserves toderive an amortization rate per reserve unit. Such amortization does not reducedistributable income, rather it is charged directly to Trust Corpus. Revisionsto estimated future units-of-production are treated on a prospective basisbeginning on the date significant revisions are known.

The Net Profits Interest impairment test and thedetermination of amortization rates are dependent on estimates of proved gasreserves attributable to the Trust. Numerous uncertainties are inherent inestimating reserve volumes and values, including economic and operatingconditions, and such estimates are subject to change as additional informationbecomes available.

*Income Taxes:*

Tax counsel to theTrust advised the Trust at the time of formation that, under then current taxlaws, the Trust would be classified as a grantor trust for federal and stateincome tax purposes and, therefore, would not be subject to taxation at theTrust level. The Trust continues to be tax exempt. Accordingly, no provisionfor federal or state income taxes has been made. However, the opinion of taxcounsel is not binding on taxing authorities.

**Recent Accounting Pronouncements**

In September 2006,the Financial Accounting Standards Board (“FASB”) issued Statement of FinancialAccounting Standards No. 158, *Employers’ Accounting forDefined Benefit Pension and Other Postretirement Plans* (“SFAS 158”),which requires the recognition of the funded status of defined benefitpostretirement plans and related disclosures. This Statement is effective for financial statements issued for fiscalyears ending after December 15, 2006. The Trust does not have Defined Benefit Pension or Other PostretirementPlans.  Therefore, SFAS 158 does notapply to the Trust and had no impact on the financial statements.

In July 2006, the FASB issued FASB Interpretation No. 48, *Accounting for Uncertainty in Income Taxes - an interpretation of FASBStatement 109* (“FIN 48”).  FIN48 prescribes a model for how a company should recognize, measure, present, anddisclose in its financial statements uncertain tab positions that it has takenor expects to take on a tax return.  Fordeferral income tax purposes, the Trust has been treated and expects tocontinue to be treated not as an association taxable as a corporation, but as agrantor trust that is not subject to Federal income tax as an entity separatefrom its beneficial owners.  Therefore,FIN 48 does not apply to the Trust and would have no impact on the financialstatements.

24

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**Liquidity and Capital Resources**

The Trust has no source of liquidity or capitalresources other than the distributions received from the Net 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, 2006. At December 31, 2006, theTrust had General and Administrative Expenses Payable of $223,442 andDistributions Payable of $2,681,087.

**Results of Operations**

##### 2006 Comparedwith 2005

The Trust’sDistributable Income was $14,158,872 for the year ended December 31, 2006 ascompared to $14,597,387 for the year ended December 31, 2005. This decrease wasdue to a decrease in Royalty Income for the year ended December 31, 2006($17,663,792) as compared to the year ended December 31, 2005 ($18,179,459).The decrease in Royalty Income was due to a decrease in production of gasattributable to the Net Profits Interests for the year ended December 31, 2006(1,847 Mmcf) as compared to the year ended December 31, 2005 (1,956 Mmcf).  This decrease was offset by an increase inthe average price payable to the Trust under the Gas Purchase Contract as discussedbelow ($9.538 per Mcf for the year ended December 31, 2006; $9.315 per Mcf forthe year ended December 31, 2005). The decline in production is primarilyattributable to natural production declines. Taxes on Production and Propertywere $1,297,539 for the year ended December 31, 2006 as compared to $1,256,330for the year ended December 31, 2005. The increase in taxes is due to a newWest Virginia tax on the Severance of Natural Resources that is effective forgas produced after November 30, 2005. The additional Severance Tax rate is four and seven-tenths cents perMCF.  Trust General and AdministrativeExpenses were $1,646,313 for the year ended December 31, 2006 as compared to$1,791,894 for the year ended December 31, 2005. The decrease in General andAdministrative Expenses was due primarily to a decrease in professional feesincurred as a direct result of the exchange offers made by Ensource EnergyIncome Fund LP, which were terminated on September 15, 2006.

During the yearended December 31, 2006, the Trustee released $500,000 from the Cash Reservebalance compared to the addition of $885,000 to the cash reserve for the year ended December 31, 2005.  This Reserve was established to facilitatethe payment of vendor invoices on a timely basis.  The change of this Reserve increased theDistribution Amount by $500,000 or $0.085 per unit for the year ended December31, 2006 and decreased the Distribution Amount by $885,000 or $0.15 per unitfor the year ended December 31, 2005. Amortization of Net Profits Interests in Gas Properties was $2,942,047for the year ended December 31, 2006 as compared to $3,321,243 for the yearended December 31, 2005. This decrease was due to the decrease in productionvolumes and a decrease in the depletion rate to $1.5932 for the year endedDecember 31, 2006 from $1.6976 for the year ended December 31, 2005, due tohigher reserves.

The average pricepayable to the Trust for gas production attributable to the Net ProfitsInterests was $9.538 per Mcf for the year ended December 31, 2006 and $9.315per Mcf for the year ended December 31, 2005. The price per Mcf was higher forthe year ended December 31, 2006 than for the corresponding year ended December31, 2005 due to an increase in the average spot market price for gas deliveredat the Henry Hub near Henry, Louisiana ($8.371 per Dth for the year endedDecember 31, 2006; $8.168 per Dth for the year ended December 31, 2005).

##### 2005 Comparedwith 2004

The Trust’sDistributable Income was $14,597,387 for the year ended December 31, 2005 as comparedto $12,019,847 for the year ended December 31, 2004. This increase was due toan increase in Royalty Income for the year ended December 31, 2005($18,179,459) as compared to the year ended December 31, 2004 ($14,449,208).The increase in Royalty Income was due to an increase in the average pricepayable to the Trust under the Gas Purchase Contract as discussed below ($9.315per Mcf for the year ended December 31, 2005; $6.989 per Mcf for the year endedDecember 31, 2004). This increase was offset by a decrease in production of gasattributable to the Net Profits Interests for the year ended December 31, 2005(1,956 Mmcf) as compared to the year ended December 31, 2004 (2,068 Mmcf). Thedecline in production is primarily attributable to natural production declinesand the sale of wells. Taxes on Production and Property were $1,256,330 for theyear ended December 31, 2005 as compared to $989,430 for the year endedDecember 31, 2004. The increase in taxes is due directly to the increase inRoyalty Income as discussed above. The production tax for the quarter alsoincludes one month of charges related to a new West Virginia tax on theSeverance of Natural Resources that is effective for gas produced afterNovember 30, 2005. The additional Severance Tax rate is four and seven-tenthscents per MCF. Trust General and Administrative Expenses were $1,791,894 forthe year ended December 31, 2005 as compared to $1,002,397 for

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the year ended December31, 2004. The increase of $789,497 in General and Administrative Expenses wasdue primarily to professional fees of approximately $725,798 incurred as adirect result of the Ensource exchange offer described above. The DistributableIncome includes no Cash Proceeds on Sale of Net Profits Interests for the year endedDecember 31, 2005, while $80,205 was recognized in the corresponding prioryear.

During the yearended December 31, 2005, the Trustee added an additional $885,000 to the CashReserve balance compared to the year ended December 31, 2004 in the amount of$100,000. This Reserve was established to facilitate the payment of vendorinvoices on a timely basis. The increase of this Reserve reduced theDistribution Amount by $885,000 or $0.15 per unit for the year ended December31, 2005 and by $100,000 or $0.0169 per unit for the year ended December 31,2004. Amortization of Net Profits Interests in Gas Properties was $3,321,243for the year ended December 31, 2005 as compared to $3,818,158 for the yearended December 31, 2004. This decrease was due to the decrease in productionvolumes and a decrease in the depletion rate to $1.6976 for the year endedDecember 31, 2005 from $1.8465 for the year ended December 31, 2004, due tohigher reserves.

The average price payable to the Trust for gasproduction attributable to the Net Profits Interests was $9.315 per Mcf for theyear ended December 31, 2005 and $6.989 per Mcf for the year ended December 31,2004. The price per Mcf was higher for the year ended December 31, 2005 thanfor the corresponding year ended December 31, 2004 due to an increase in theaverage spot market price for gas delivered at the Henry Hub near Henry,Louisiana ($8.168 per Dth for the year ended December 31, 2005; $6.054 per Dthfor the year ended December 31, 2004).

**Off-BalanceSheet Arrangements**

TheTrust does not have any off-balance sheet arrangements that have or arereasonably likely to have a current or future effect on the Trust’s financialcondition, changes in financial condition, revenue or expenses, results of operations,liquidity, capital expenditures or capital resources that is material toinvestors.

**Item 7A.   *Quantitativeand Qualitative Disclosures About Market Risk.***

The Trust does not engage in any operations and doesnot utilize market risk sensitive instruments, either for trading purposes orfor other than trading purposes. As described in detail elsewhere herein, theDepositary Units consist of beneficial ownership of one unit of beneficialinterest in the Trust and a $20 face amount beneficial ownership interest in a$1,000 face amount zero coupon Treasury Obligation maturing on May 15, 2013.High and low price information for the Treasury Obligations is included underItem 5. As described in detail elsewhere herein, gas production attributable tothe Net Profits Interest is sold to a wholly owned subsidiary of EasternAmerican pursuant to the Gas Purchase Contract 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, 2006 and 2005        |   |
| Statements of  Distributable Income for the years ended December 31, 2006, 2005 and 2004    |   |
| Statements of  Changes in Trust Corpus for the years ended December 31, 2006, 2005 and 2004 |   |
| Notes to Financial  Statements                                                              |   |
| Supplemental Information                                                                    |   |

 

**Item 9.*****    Changesin and Disagreements with Accountants on Accounting and Financial Disclosure.***

None.

**Item 9A.  *Controls andProcedures.***

**Evaluation of Disclosure Controls and Procedures**

The Trustee maintains disclosure controls andprocedures designed to ensure that information required to be disclosed by theTrust in the reports that it files or submits under the Securities Exchange Actof 1934, as amended, is recorded, processed, summarized and reported within thetime periods specified in the SEC’s rules and regulations.  Disclosurecontrols and procedures include controls and procedures designed to ensure thatinformation required to be disclosed by the Trust is accumulated andcommunicated by several parties, including without limitation, the workinginterest owner, Eastern American Energy Corporation (“Eastern American”), andthe independent reserve engineer to The Bank of New York Trust Company, 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

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financialstatements of the Trust and audit the annual financial statements of the Trust,which includes financial data provided by Eastern American.

As of December 31, 2006, the Trustee carried outan evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich,as Trust Officer of the Trustee, has concluded that the disclosure controls andprocedures are effective.

Due to the contractual arrangements of (i) the TrustAgreement and (ii) the rights of the Trustee under the Conveyances regardinginformation furnished by Eastern American, there are certain potentialweaknesses that may limit the effectiveness of disclosure controls andprocedures established by the Trustee or its employees and their ability toverify 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 Trustee necessarily relies upon theindependent reserve engineer, as an expert with respect to the annual reservereport, which includes projected production, operating expenses and capitalexpenses.

Other than reviewing the financial and otherinformation provided to the Trust by Eastern American and the independentreserve engineer, the Trustee made no independent or direct verification ofthis financial or other information.

The Trustee does not intend to expand itsresponsibilities beyond those permitted or required by the Trust Agreement andthose required under applicable law.

The Trustee does not expect that the Trustee’sdisclosure controls and procedures or the Trustee’s internal control overfinancial reporting will prevent all errors and all fraud.  Further, the design of disclosure controlsand procedures and internal control over financial reporting must reflect thefact that there are resource constraints, and the benefits of controls must beconsidered relative to their costs. Because of the inherent limitations in all control systems, no evaluationof controls can provide absolute assurance that all control issues andinstances of fraud, if any, have been detected.

**Changes in Internal Control Over Financial Reporting**

In connection with the evaluation by the Trustee ofchanges in internal control over financial reporting of the Trust that occurredduring the Trust’s last fiscal quarter, no change in the Trust’s internalcontrol over financial reporting was identified that has materially affected,or is reasonably likely to materially affect, the Trust’s internal control overfinancial reporting.

**Trustee’s Report on Internal Control over Financial Reporting**

The Trustee is responsible for establishing andmaintaining adequate internal control over financial reporting, as such term isdefined in Rule 13a-15(f) promulgated under the Securities and ExchangeAct of 1934, as amended. The Trustee conducted an evaluation of theeffectiveness of the Trust’s internal control over financial reporting based onthe criteria established in *InternalControl-Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission. Based on the Trustee’s evaluationunder the framework in *InternalControl-Integrated Framework*, the Trustee concluded that the Trust’sinternal control over financial reporting was effective as of December 31,2006. The Trustee’s assessment of the effectiveness of the Trust’s internalcontrol over financial reporting as of December 31, 2006 has been auditedby PricewaterhouseCoopers LLP, an independent registered public accountingfirm, as stated in their report which is included herein.

A registrant’s internal control over financialreporting is a process designed to provide reasonable assurance regarding thereliability of financial reporting and the preparation of financial statementsfor external purposes in accordance with generally accepted accountingprinciples. A registrant’s internal control over financial reporting includesthose policies and procedures that (i) pertain to the maintenance of recordsthat, in reasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the registrant; (ii) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, andthat receipts and expenditures of the registrant are being made only inaccordance with authorizations of management and directors of the registrant;and (iii) provide reasonable assurance regarding prevention or timely detectionof unauthorized acquisition, use, or disposition of the registrant s assetsthat could have a material effect on the financial statements.

Because of its inherent limitations, internal controlover financial reporting may not prevent or detect misstatements.

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Also,projections of any evaluation of effectiveness to future periods are subject tothe risk that controls may become inadequate because of changes in conditions,or that the degree of compliance with the policies or procedures maydeteriorate.

**Item 9B.****  *OtherInformation.***

None.

**PART III**

**Item 10.****   *Directors, Executive Officers and Corporate Governance.***

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.

The Trust also does nothave an audit committee or body serving a similar function. The Trust has notadopted a code of ethics, as the Trust has no directors, officers, oremployees. The Trust has not adopted a process by which Unitholders maycommunicate with board members, as the Trust has no board members or personsfulfilling a similar function. Unitholders may contact the Trustee at thefollowing address:  The Bank of New YorkTrust Company, N.A., Trustee of Eastern American Natural Gas Trust,  Global Corporate Trust, 919 Congress AvenueSuite 500, Austin, Texas 78701.

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

The Trust has no officersor directors, and is administered by the Trustee. For the year ended December31, 2006, The Bank of New York Trust Company, N.A., as Trustee, received$108,000, for the year ended December 31, 2005, JPMorgan Chase Bank, N.A.received $108,000 and for the year ended December 2004, The Bank of New York,as Trustee, received $45,000 annually, as Trustee fees and $1,209,881,$1,366,570 and $650,805, respectively, as reimbursement of legal, accounting,and other professional expenses for such services. Effective January 1, 2005,the annual Trustee fee was fixed at $108,000.

**Item 12.****   *Security Ownership of Certain Beneficial Owners and Management andRelated Stockholder Matters.***

(a)           SecurityOwnership of Certain Beneficial Owners.

Based on filingswith the Securities and Exchange Commission, the Trust is not aware of anyperson owning beneficially more than 5% of the Units as of March 1, 2007.

(b)           SecurityOwnership of Management.

Not applicable.

(c)           Changesin Control.

The Trust knows ofno arrangements, including the pledge of securities of the Trust, the operationof which may at a subsequent date result in a change in control of the Trust.

(d)           Securitiesauthorized for issuance under equity compensation plans.

The Trust has no equity compensation plans.

**Item 13.****   *Certain Relationships and Related Transactions, and DirectorIndependence.***

The Trust has no directors.

**Item 14.****   *Principal Accounting Fees and Services.***

**Audit Fees**

The fees PricewaterhouseCoopers LLP billed the Trustfor each of the last two fiscal years for professional services rendered inconnection with the audits of the Trust’s annual financial statements andreview of the Trust quarterly interim financial statements were $193,516 in2006 and $185,250 in 2005.

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**Audit-Related Fees**

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.

**Tax Fees**

The fees, including expenses, PricewaterhouseCoopersLLP billed the Trust for each of the last two fiscal years for compliance, taxadvice, or planning were $128,000 in 2006 and $123,715 in 2005.

**All Other Fees**

PricewaterhouseCoopers LLP did not bill the Trust anyadditional fees in the last two fiscal years for products and services providedby PricewaterhouseCoopers LLP, other than services reported above.

**Pre-Approval Policies**

The Trust does not have an audit committee or bodyperforming a similar function. Pre-approval of all services performed byPricewaterhouseCoopers LLP and approval of the related fees is granted by theTrustee.

**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, 2006 and 2005        |   |
|                                                                                                         | Statements of  Distributable Income for the years ended December 31, 2006, 2005 and 2004    |   |
|                                                                                                         | Statements of  Changes in Trust Corpus for the years ended December 31, 2006, 2005 and 2004 |   |
|                                                                                                         | Notes to Financial  Statements                                                              |   |
|                                                                                                         | Supplemental Information                                                                    |   |

 

Schedules

Allschedules have been omitted because they are not required, not applicable orthe information required has been included elsewhere herein.

Exhibits

Except as otherwise indicated below, all exhibits,except Exhibit 31 and Exhibit 32, are incorporated herein by reference to theindicated exhibits to filings previously made by the registrant with theSecurities and Exchange Commission. All references are to the registrant’sRegistration Statement on Form S-1, Registration No. 33-56336, except forExhibit 3.1, which is incorporated by reference to the Registrant’s AnnualReport on Form 10-K for the year ended December 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 |

 

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**SIGNATURES**

**Pursuant to the requirements of Section 13 or15(d) of the Securities Exchange Act of 1934, the registrant has duly causedthis report to be signed on its behalf by the undersigned, thereunto dulyauthorized on this 16th day of March, 2007.**
|        | EASTERN AMERICAN  NATURAL GAS TRUST |
|--------|-------------------------------------|
|   |                                |
|   | By:                                 | The Bank of New  York Trust Company, N.A., Trustee |
|   |                                |
|   | By:                                 | /s/ Mike Ulrich |   |
|   | Name:                               | Mike Ulrich |
|   | Title:                              | Vice President |

 

The Registrant, Eastern American Natural Gas Trust,has no principal executive officer, principal financial officer, controller orprincipal accounting officer, board of directors or persons performing similarfunctions. Accordingly, no additional signatures are available and none havebeen provided.

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[Ryder Scott Company,Independent Petroleum Engineers Letterhead]

January 29, 2007

Eastern AmericanNatural Gas Trust

The Bank of NewYork Trust Company, N.A.

919 CongressAvenue

Suite 500

Austin, Texas 78701

Gentlemen:

Pursuantto your request, we present below estimates of the net proved reservesattributable to the interests of the Eastern American Natural Gas Trust (Trust)as of December 31, 2006.  The Trust is agrantor trust formed to hold interests in certain domestic oil and gasproperties owned by Eastern American Energy Corporation (EAEC), a wholly ownedsubsidiary of Energy Corporation of America (ECA).  The interests conveyed to the Trust consistof a net profits interest derived from working and royalty interests innumerous properties.  The Net ProfitsInterest consists of (1) a life-of-properties interest (“Royalty NPI”) and (2)a term interest (“Term NPI”).  Theproperties included in the Trust are located in the states of Pennsylvania andWest Virginia.

The estimated reserve quantities and future incomequantities presented in this report are related to a large extent tohydrocarbon prices.  Hydrocarbon pricesin effect at December 31, 2006 were used in the preparation of this report asrequired by Securities and Exchange Commission (SEC) and Financial AccountingStandards Bulletin No. 69 (FASB 69) guidelines; however, actual future pricesmay vary significantly from December 31, 2006 prices for reasons discussed inmore detail in other sections of this report. Therefore, quantities of reserves actually recovered and quantities ofincome actually received may differ significantly from the estimated quantitiespresented in this report.
| ** **           | ** ** | **As of December 31, 2006** | ** ** | ** **                                        | ** ** |
|----------------------|------------|-------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **           | ** ** | **Gas**                                         | ** ** | **Estimated  Future Net  Cash Inflows** | ** ** | **Present  Value  At 10%** | ** ** |
| ** **           | ** ** | **(MMCF)**                                      | ** ** | **(M$)**                                          | ** ** | **(M$)** | ** ** |
| Proved Net Developed |       |                                            |       |                                              |       |   |   |
|                 |       |                                            |       |                                              |       |   |   |
| Royalty NPI          |       | 9,885                                           |       | 80,027                                            |       | 33,779 |   |
| Term NPI             |       | 4,814                                           |       | 38,977                                            |       | 29,481 |   |
| Total                |       | 14,699                                          |       | 119,004                                           |       | 63,260 |   |

 

Reserve quantities are calculated differently for aNet Profits Interest because such interests do not entitle the Trust to aspecific quantity of oil or gas but to 90 percent of the Net Proceeds derivedtherefrom beginning on January 1, 2007 for natural gas.  Accordingly, there is no precise method ofallocating estimates of the quantities of proved reserves attributable to theNet Profits Interest between the interest held by the Trust and the intereststo be retained by EAEC.  For purposes ofthis presentation, 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, thereserves presented for the Net Profits Interest reflect quantities of gas thatare free of future costs or expenses based on the price and cost assumptionsutilized 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, EAECrequested that for purposes of our report the “Royalty NPI” be calculatedbeyond the Liquidation Date of May 15, 2013, even though by the terms of theTrust Agreement the Royalty NPI will be sold by the Trustee on or about thisdate and a liquidating distribution of the sales proceeds from such sale wouldbe made to holders of Trust Units.  TheTrust Agreement provides that the “Term NPI” entitles the Trust to receive thenet proceeds from the gas produced from the properties burdened by the “TermNPI” until the earlier of May 15, 2013 or until such time as 41,683 MMCF of gashas been produced.  For purposes of thisreport, the “Term NPI” was limited to May 15, 2013.

All gas volumes are sales gas expressed in MMCF at thepressure and temperature bases of the area where the gas reserves arelocated.  The estimated future net cashinflows are described later in this report.

The proved reserves presented in this report complywith the Securities and Exchange Commission’s Regulation S-X Part 210.4-10 Sec.(a) as clarified by subsequent Commission Staff Accounting Bulletins, and arebased on the following definitions and criteria:

A-1

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Proved reserves of crude oil,natural gas, or natural gas liquids are estimated quantities that geologicaland engineering data demonstrate with reasonable certainty to be recoverable inthe future from known reservoirs under existing conditions.  Reservoirs are considered proved if economicproducibility is supported by actual production 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 areservoir considered proved includes (1) that portion delineated by drillingand defined by fluid contacts, if any, and (2) the adjoining portions not yetdrilled that can be reasonably judged as economically productive on the basisof available geological and engineering data. In the absence of data on fluid contacts, the lowest known structuraloccurrence of hydrocarbons controls the lower proved limit of thereservoir.  Proved reserves are estimatesof hydrocarbons to be recovered from a given date forward.  They may be revised as hydrocarbons areproduced and additional data becomes available. Proved natural gas reservesconsist of non-associated, associated and dissolved gas.  An appropriate reduction in gas reserves hasbeen made for the expected removal of natural gas liquids, for lease and plantfuel, and for the exclusion of non-hydrocarbon gases if they occur insignificant quantities.

Reserves that can be produced economically through theapplication of improved recovery techniques are included in the provedclassification when these qualifications are met:  (1) successful testing by a pilot project orthe operation of an installed program in the reservoir provides support for theengineering analysis on which the project or program was based, and (2) it isreasonably certain the project will proceed. Improved recovery includes all methods for supplementing naturalreservoir forces and energy, or otherwise increasing ultimate recovery from areservoir, including (1) pressure maintenance, (2) cycling, and (3) secondaryrecovery 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 proved reserves do not include crude oil,natural gas, or natural gas liquids being held in underground or surfacestorage.

(i) “developedreserves” which are those proved reserves reasonably expected to be recoveredthrough existing wells with existing equipment and operating methods, including(a) “developed producing reserves” which are those proved developed reservesreasonably expected to be produced from existing completion intervals now openfor production in existing wells, and (b) “developed non-producingreserves” which are those proved developed reserves which exist behind thecasing of existing wells which are reasonably expected to be produced throughthese wells in the predictable future where the cost of making such hydrocarbonsavailable for production should be relatively small compared to the cost of anew 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 undrilledacreage are limited to those drilling units offsetting productive units thatare reasonably certain of production when drilled.  Proved reserves for other undrilled units areincluded only where it can be demonstrated with reasonable certainty that thereis continuity of production from the existing productive formation.

In accordance with the requirements of FASB 69,estimates of future cash inflows, future costs and future net cash inflowsbefore income tax, as well as estimated reserve quantities, as of December 31,2006 from this report are presented in the following table:
|                                                 | ** ** | **As of December 31, 2006** | ** ** |
|-------------------------------------------------|------------|-------------------------------------------------|------------|
| ** **                                      | ** ** | **Royalty  NPI**                                | ** ** | **Term  NPI** | ** ** | **Totals** | ** ** |
| Total Proved                                    |       |                                            |       |   |   |   |   |
| Future Cash Inflows (M$)                        |       | 80,027                                          |       | 38,977 |   | 119,004 |   |
| Future Costs                                    |       |                                            |       |   |   |   |   |
| Production (M$)                                 |       | 0                                               |       | 0 |   | 0 |   |
| Development (M$)                                |       | 0                                               |       | 0 |   | 0 |   |
| Total Costs (M$)                                |       | 0                                               |       | 0 |   | 0 |   |
|                                            |       |                                            |       |   |   |   |   |
| Future Net Cash  Inflows Before Income Tax (M$) |       | 80,027                                          |       | 38,977 |   | 119,004 |   |
|                                            |       |                                            |       |   |   |   |   |
| Present Value at 10%  Before Income Tax (M$)    |       | 33,779                                          |       | 29,481 |   | 63,260 |   |

 

A-2

----

 
|                                  | ** ** | **As of December 31, 2006** | ** ** |
|----------------------------------|------------|-------------------------------------------------|------------|
| ** **                       | ** ** | **Royalty  NPI**                                | ** ** | **Term  NPI** | ** ** | **Totals** | ** ** |
| Proved Net  Developed Reserves   |       |                                            |       |   |   |   |   |
| Gas (MMCF)                       |       | 9,885                                           |       | 4,814 |   | 14,699 |   |
|                             |       |                                            |       |   |   |   |   |
| Proved Net  Undeveloped Reserves |       |                                            |       |   |   |   |   |
| Gas (MMCF)                       |       | 0                                               |       | 0 |   | 0 |   |
|                             |       |                                            |       |   |   |   |   |
| Total Proved Net  Reserves       |       |                                            |       |   |   |   |   |
| Gas (MMCF)                       |       | 9,885                                           |       | 4,814 |   | 14,699 |   |

 

For Net Profits Interest, the future cash inflows are,as described previously, after consideration of future costs or expenses basedon the price and cost assumptions utilized in this report.  Therefore, the future cash inflows are thesame as the future net cash inflows.  Theeffects of depreciation, depletion and federal income taxes have not been takeninto account in estimating future net cash inflows.

EAEC furnished us gas prices in effect at December 31,2006 and with its forecasts of future gas prices which take into accountSecurities and Exchange Commission guidelines, current market prices, contractprices and fixed and determinable price escalations 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.  Inthose cases where contract market-out has occurred, the current market pricewas held constant to depletion of the reserves. In those cases where market-out has not occurred, contract gas pricesincluding fixed and determinable escalations, exclusive of inflationadjustments, were used until the contract expired and then reduced to thecurrent market price for similar gas in the area and held at this reduced priceto depletion of the reserves.

This report utilized the terms of the gas contractbetween Eastern Marketing Corporation (a wholly owned subsidiary of EAEC) andthe Trust.  Gas price is to be determinedby a weighted price consisting of two components during a primary term definedto begin on January 1, 1993 and end December 31, 1999.  The first component is the “Fixed” pricewhich has been defined as $2.66 per Mcf beginning January 1, 1993.  This price escalates 5 percent per year on January1 of each year during the primary term beginning in 1994. The second componentis the “Variable” price which for any quarter is equal to the Henry Hub AverageSpot Price (as defined) per MMBtu, plus $0.30 per MMBtu, multiplied by 110percent to effect a Btu adjustment.  TheHenry Hub Average Spot Price is defined as the price per MMBtu determined forany calendar quarter as the average price of the three months in such quarterwhere each month’s price is equal to the average of (i) the final settlementprices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reportedin the Wall Street Journal, for such contracts which expired in each ofthe five months prior to each month of such quarter, (ii) the final settlementprice per MMBtu for Henry Hub Gas Futures Contracts, as reported in the WallStreet Journal, for such contracts which expire during such month and (iii)the closing settlement prices per MMBtu of Henry Hub Gas Futures Contracts forsuch month, as reported in the Wall Street Journal, for such contractswhich expire in each of the six months following such month.  A Henry Hub Gas Futures Contract is definedas a gas futures contract for gas to be delivered to the Henry Hub which istraded on the New York Mercantile Exchange. The weighted average price is determined by giving the “Fixed” price a66 2/3 percent weighting and the variable price a 33 1/3 percent weighting.

Since the primary term is complete, the purchase priceunder the gas contract will be equal to the “Variable” price.  EAEC computed the “Variable” price under thegas contract as of December 31, 2006 as $8.096 per Mcf, utilizing $7.060 as theHenry Hub Average Spot Price computed in accordance with the gas contract.

Operating costs for the leases and wells in this reportwere supplied by EAEC and include only costs defined as applicable under termsof the Trust.  The current operatingcosts were held constant throughout the life of the properties.  This study does not consider the salvagevalue of the lease equipment or the abandonment cost.

No deduction was made for indirect costs such asgeneral administration and overhead expenses, loan repayments, interestexpenses, and exploration and development prepayments.  No attempt has been made to quantify orotherwise account for any accumulated gas production imbalances that may exist.

Our reserve estimates are based upon a study of theproperties in which the Trust has interests; however, we have not made anyfield examination of the properties.  Noconsideration was given in this report to potential environmental

A-3

----

liabilities which may exist nor were any costs included for potentialliability to restore and clean up damages, in any, caused by past operatingpractices.  EAEC informed us that it hasfurnished us all of the accounts, records, geological and engineering data andreports and other data as were required for our investigation. The ownershipinterests, terms of the Trust, prices, taxes, and other factual data furnishedto us in connection with our investigation were accepted as represented.  The estimates presented in this report arebased on data available through September, 2006.

At the time of formation of the Trust, EAEC assignedThe Trust an interest in 65 undeveloped locations.  During the period 1993 through 1998, EAEC hascompleted it’s drilling obligation. A total of 59 wells were drilled over thisperiod.  Two wells were not drilled dueto title failure and four wells were not drilled due to short spacing.  Reserves and projections of future productionare included for the four locations which were not drilled due to shortspacing.

The reserves included in this report are estimatesonly and should not be construed as being exact quantities.  They may or may not be actuallyrecovered.  Moreover, estimates of provedreserves may increase or decrease as a result of future operations ofEAEC.  Moreover, due to the nature of theNet Profits Interest, a change in the future costs, or prices different fromthose projected herein may result in a change in the computed reserves and theNet Proceeds to the Trust even if there are no revisions or additions to thegross reserves attributed to the property.

The future production rates from properties now onproduction may be more or less than estimated because of changes in marketdemand or allowables set by regulatory bodies. Properties which are not currently producing may start producing earlieror later than anticipated in our estimates of their future production rates.

The future prices received by EAEC for the sale of itsproduction may be higher or lower than the prices used in this report asdescribed above, and the operating costs and other costs relating to suchproduction may also increase or decrease from existing levels; however, suchpossible changes in prices and costs were, in accordance with rules adopted bythe Securities and Exchange Commission, omitted from consideration in preparingthis report.

At the request of EAEC, we have included the followingtable which summarizes the total net reserves estimates from combined interestof EAEC and the Trust in the Underlying Properties:

Estimated Net Reserve Data

Certain Combined Leasehold Interests of

Eastern America Energy Corporation

And The Trust

As of December 31, 2006

SEC Parameters
|                         | ** ** | **Proved**    | ** ** | **Total**       | ** ** |
|-------------------------|------------|---------------|------------|-----------------|------------|
| ** **              | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Proved** | ** ** |
| Net Remaining  Reserves |       |          |       |            |       |   |   |
|                    |       |          |       |            |       |   |   |
| Gas-MMCF                |       | 31,802        |       | 0               |       | 31,802 |   |

 

The estimated future net income associated with theforegoing volumes and the 10 percent discounted estimated future net income was$215,728,419 and $88,414,492, respectively. This evaluation utilizes the same price and cost assumptions that wereutilized for evaluating the Trust and discussed earlier in the letter.  The properties which are included in the “TermNPI” were allowed to run for their full economic life in this evaluation.

Neither Ryder Scott Company nor any of its employeeshas any interest in the subject properties and neither the employment to makethis study nor the compensation is contingent on our estimates of reserves andfuture cash inflows for the subject properties.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

LarryT. Nelms P. E.

Managing Senior Vice President

LTN:ph

A-4

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EASTERN AMERICAN NATURAL GAS TRUST

----

FINANCIAL STATEMENTS

as of December 31, 2006 and 2005

and for the years ended

December 31, 2006, 2005 and 2004

----

Report of Independent Registered Public AccountingFirm

Tothe Unit Holders of Eastern American Natural Gas Trust and The Bank of New YorkTrust Company, N.A., Trustee:

We have completed integratedaudits of Eastern American Natural Gas Trust’s financial statements and of itsinternal control over financial reporting as of December 31, 2006, inaccordance with the standards of the Public Company Accounting Oversight Board(United States).  Our opinions, based on our audits, are presented below.

Financial statements

Wehave audited the accompanying statements of assets, liabilities and trustcorpus of Eastern American Natural Gas Trust (the “Trust”) as ofDecember 31, 2006 and 2005, and the related statements of distributableincome, and statements of changes in trust corpus for each of the three yearsin the period ended December 31, 2006.  These financial statementsare the responsibility of the Trustee.  Our responsibility is to expressan opinion 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 31,2006 and 2005, and the distributable income and changes in trust corpus foreach of the three years in the period ended December 31, 2006, on thebasis of accounting described in Note 2.

Internal control over financial reporting

Also, in our opinion, the Trustee’s assessment, included in the Trustee’sReport on Internal Control over Financial Reporting appearing under Item 9A,that the Trust maintained effective internal control over financial reportingas of December 31, 2006basedon 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 overfinancial reporting as of December 31, 2006, based on criteria established in *Internal Control - Integrated Framework* issued by theCOSO.  The Trustee is responsible formaintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financialreporting.  Our responsibility is toexpress opinions on the Trustee’s assessment and on the effectiveness ofthe Trust’s internal control over financial reporting based on our audit. Weconducted our audit of internal control over financial reporting in accordancewith the standards of the Public Company Accounting Oversight Board (UnitedStates).  Those standards require that weplan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in allmaterial respects.  An audit of internalcontrol over financial reporting includes obtaining an understanding ofinternal control over financial reporting, evaluating the Trustee’s assessment,testing and evaluating the design and operating effectiveness of internalcontrol, and performing such other procedures as we consider necessary in thecircumstances.  We believe that our auditprovides 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 over financial reporting includes thosepolicies and procedures that (i) pertain to the maintenance of recordsthat, in reasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the trust; (ii) provide reasonable assurancethat transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, andthat receipts and expenditures of the trust are being made only in accordancewith authorizations of the trustee; and (iii) provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use, ordisposition of the trust’s assets that could have a material effect on thefinancial statements.

F-2

----

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

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

March16, 2007

F-3

----

**EASTERN AMERICAN NATURAL GASTRUST**

**STATEMENTSOF ASSETS, LIABILITIES AND TRUST CORPUS**

**as ofDecember 31, 2006 and 2005**
| ** **                                                       | ** ** | **2006**    | ** ** | **2005**    | ** ** |
|------------------------------------------------------------------|------------|-------------|------------|-------------|------------|
|                                                             |       |        |       |        |       |
| Assets:                                                          |       |        |       |        |       |
|                                                             |       |        |       |        |       |
| Cash                                                             |       | $           | 590,585    |        | $          | 43,478 |   |
| Net Proceeds Receivable                                          |       | 3,013,944   |       | 5,408,091   |       |
| Net Profits Interests in Gas Properties                          |       | 93,162,180  |       | 93,162,180  |       |
| Accumulated Amortization                                         |       | (68,600,962 | )          | (65,658,915 | )          |
|                                                             |       |        |       |        |       |
| Total Assets                                                     |       | $           | 28,165,747 |        | $          | 32,954,834 |   |
|                                                             |       |        |       |        |       |
| Liabilities and  Trust Corpus:                                   |       |        |       |        |       |
|                                                             |       |        |       |        |       |
| Trust General and Administrative Expenses Payable                |       | $           | 223,442    |        | $          | 318,120 |   |
| Distributions Payable                                            |       | 2,681,087   |       | 3,933,449   |       |
| Trust Corpus (5,900,000 Trust Units authorized and  outstanding) |       | 25,261,218  |       | 28,703,265  |       |
|                                                             |       |        |       |        |       |
| Total  Liabilities and Trust Corpus                              |       | $           | 28,165,747 |        | $          | 32,954,834 |   |

 

**The accompanying notes are anintegral part of these financial statements.**

F-4

----

**EASTERN AMERICAN NATURAL GASTRUST**

**STATEMENTSOF DISTRIBUTABLE INCOME**

**for the years ended**

**December31, 2006, 2005 and 2004**
| ** **                                                                  | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-----------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
|                                                                        |       |       |       |       |       |       |       |
| Royalty Income                                                              |       | $          | 17,663,792 |       | $          | 18,179,459 |       | $ | 14,449,208 |   |
|                                                                        |       |       |       |       |       |       |       |
| Operating  Expenses:                                                        |       |       |       |       |       |       |       |
| Taxes on Production and Property                                            |       | 1,297,539  |       | 1,256,330  |       | 989,430    |       |
| Operating Cost Charges                                                      |       | 561,068    |       | 534,348    |       | 519,228    |       |
|                                                                        |       |       |       |       |       |       |       |
| Total Operating Expenses                                                    |       | 1,858,607  |       | 1,790,678  |       | 1,508,658  |       |
|                                                                        |       |       |       |       |       |       |       |
| Net Proceeds to  the Trust                                                  |       | 15,805,185 |       | 16,388,781 |       | 12,940,550 |       |
|                                                                        |       |       |       |       |       |       |       |
| General and  Administrative Expenses                                        |       | (1,646,313 | )          | (1,791,894 | )          | (1,002,397 | )          |
|                                                                        |       |       |       |       |       |       |       |
| Interest Income                                                             |       | —     |       | 500        |       | 1,489      |       |
|                                                                        |       |       |       |       |       |       |       |
| Cash Proceeds on  Sale of Net Profits Interests                             |       | —     |       | —     |       | 80,205     |       |
|                                                                        |       |       |       |       |       |       |       |
| Distributable Income                                                        |       | 14,158,872 |       | 14,597,387 |       | 12,019,847 |       |
|                                                                        |       |       |       |       |       |       |       |
| Cash Reserve  Refunded (Withheld)                                           |       | 500,000    |       | (885,000   | )          | (100,000   | )          |
|                                                                        |       |       |       |       |       |       |       |
| Distribution Amount                                                         |       | $          | 14,658,872 |       | $          | 13,712,387 |       | $ | 11,919,847 |   |
|                                                                        |       |       |       |       |       |       |       |
| Distributable  Income Per Unit (5,900,000 units authorized and outstanding) |       | $          | 2.3998     |       | $          | 2.4741     |       | $ | 2.0373 |   |
|                                                                        |       |       |       |       |       |       |       |
| Distribution Amount Per  Unit (5,900,000 units authorized and outstanding)  |       | $          | 2.4846     |       | $          | 2.3241     |       | $ | 2.0203 |   |

 

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

F-5

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**EASTERN AMERICAN NATURAL GAS TRUST**

**STATEMENTS OF CHANGES IN TRUSTCORPUS**

**for the years ended**

**December31, 2006, 2005 and 2004**
| ** **                                               | ** ** | **2006**    | ** ** | **2005**    | ** ** | **2004**    | ** ** |
|----------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|
|                                                     |       |        |       |        |       |        |       |
| Trust Corpus,  Beginning of Period                       |       | $           | 28,703,265 |        | $          | 31,139,508  |       | $ | 34,857,666 |   |
| Distributable  Income                                    |       | 14,158,872  |       | 14,597,387  |       | 12,019,847  |       |
| Distributions  Paid or Payable to Unitholders            |       | (14,658,872 | )          | (13,712,387 | )          | (11,919,847 | )          |
| Amortization of Net Profits Interests in Gas  Properties |       | (2,942,047  | )          | (3,321,243  | )          | (3,818,158  | )          |
|                                                     |       |        |       |        |       |        |       |
| Trust Corpus, End of  Period                             |       | $           | 25,261,218 |        | $          | 28,703,265  |       | $ | 31,139,508 |   |

 

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

F-6

----

EASTERN AMERICANNATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS

1.             Organization of the Trust:

TheEastern American Natural Gas Trust (the “Trust”) was formed under the DelawareBusiness Trust Act pursuant to a Trust Agreement (the “Trust Agreement”) amongEastern American Energy Corporation (“Eastern American”), as grantor, Bank ofMontreal Trust Company, as Trustee, and Wilmington Trust Company, as DelawareTrustee (the “Delaware Trustee”). Effective May 8, 2000, The Bank of New Yorkacquired the corporate trust business of the Bank of Montreal Trust Company /Harris Trust, and consequently, The Bank of New York served as trustee of theTrust. On November 20, 2004, the holders of a majority of the Trust Unitsvoting at a special meeting approved the resignation of The Bank of New York astrustee and depository of the Trust and the appointment of JPMorgan Chase Bank,N.A. as successor trustee of the Trust, effective as of January 1, 2005.  Effective October 2, 2006, The Bank of NewYork Trust Company, N. A. replaced JPMorgan Chase Bank, N.A. as trustee inconnection with the sale by JPMorgan Chase Bank of substantially all of itscorporate trust business to The Bank of New York.  Consequently, references herein to the “Trustee”mean Bank of Montreal Trust Company until May 8, 2000; The Bank of New York assuccessor Trustee from May 8, 2000 through December 31, 2004; JPMorgan ChaseBank, N.A. as successor trustee, from January 1, 2005 through October 2, 2006;and The Bank of New York, N.A. as successor trustee, effective as of October 2,2006.  The transfer agent for the Trustis Bondholder Communications, an affiliate of The Bank of New York TrustCompany, N.A.

Thepurpose of the Trust is to acquire and hold net profits interests owned byEastern American in 650 producing gas wells and 65 proved development welllocations in West Virginia and Pennsylvania (the “Underlying Properties”). TheUnderlying Properties are operated by Eastern American. The Net ProfitsInterests (the “Net Profits Interests”) consist of a Royalty interest in 322wells and a Term interest in the remaining wells and locations. EasternAmerican drilled 59 of the 65 development wells.

TheRoyalty NPI is not limited in term or amount. Under the Trust Agreement, theTrustee is directed to sell all remaining Royalty NPI after May 15, 2012 andprior to May 15, 2013, and net proceeds from selling such Royalty NPI will bedistributed to Unitholders on the first quarterly payment date following thereceipt of such proceeds by the Trust. The Term NPI will expire on the earlierof May 15, 2013 or such time as 41,683 MMcf of gas has been produced which isattributable to Eastern American’s net revenue interests in the propertiesburdened by the Term NPI. As of December 31, 2006, 23,661 MMcf of such gas hadbeen produced.

EasternAmerican can sell the Underlying Properties, subject to and burdened by the NetProfits Interests, without the consent of the Trustee or the Unitholders. Inlimited circumstances, Eastern American also can transfer the Underlying Propertiesand require 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 wellincluded in the Underlying Properties or the Development Wells will extinguishthat portion of the Net Profits Interests that relate to such well.

Four(4) of the remaining six (6) development wells were closely offset by thirdparties. Since the wells drilled by the third parties were within 1,000 feet ofthese development wells, Eastern American had a disagreement with the Trustover Eastern American’s obligation to drill these closely offset developmentwells. The Trust agreed that, in lieu of drilling these closely offsetdevelopment wells Eastern American can provide the Trust, on an annual basiscommencing on April 1, 1997, and over the remaining life of the Trust, a volumeof gas which is equal to the projected volumes of the wells as if they had beendrilled. These volumes have been estimated by the Ryder Scott Company.

Thetwo (2) remaining development wells were not drilled because Eastern Americanwas unable to cure various title defects associated with these wells. EasternAmerican advised the Trust that it made a diligent effort to cure title but wasunsuccessful. In West Virginia, an oil and gas well cannot be drilled unless afull and complete 100% leasehold interest is first obtained. Drilling an oiland gas well without obtaining the entire leasehold estate would expose the oiland gas operator and the Trust to a possible suit for trespass. Pursuant to theTerm Net Profits Interest Conveyance, if the state of title to the drill siteto any development well renders such property undrillable in the good faith opinionof Eastern American under the Reasonably Prudent Operator Standard then suchdrill site(s) shall be construed as a development well(s). Consequently,Eastern American has fulfilled its commitment to the Trust to drill therequired number of development wells.

OnMarch 15, 1993, 5,900,000 depositary units were issued in a public offering atan initial public offering price of $20.50 per depositary unit. Each depositaryunit consists 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 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

F-7

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EASTERN AMERICANNATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS

considerationfor the conveyance of the Net Profits Interests to the Trust. The Trustacquired the Net Profits Interests effective as of January 1, 1993. TheTreasury Obligations are directly owned by the Unitholders and are not part ofthe Trust Corpus. The Treasury Obligations are on deposit with the Trusteepursuant to the Deposit Agreement.

TheNet Profits Interests are passive in nature, and neither the Trustee nor theDelaware Trustee has management control or authority over, nor anyresponsibility relating to, the operation of the properties 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 the Trustee will make quarterly cash distributions toUnitholders from funds of the Trust.

2.                                                          SignificantAccounting Policies:

Thefollowing is a summary of the significant accounting policies followed by theTrust.

*Basis of Accounting:*

Thefinancial statements of the Trust differ from financial statements prepared inaccordance with accounting principles generally accepted in the United Statesof America due to the following: i) certain cash reserves may be establishedfor contingencies which were not accrued in the financial statements; ii)amortization of the Net Profits Interests in gas properties is charged directlyto Trust Corpus; and iii) the sale of the Net Profits Interests is reflected inthe Statements of Distributable Income as cash proceeds to the Trust.

*Cash:*

Cashconsists of highly liquid instruments with maturities at the time ofacquisition of three months or less.

*NetProfits Interests in Gas Properties:*

TheNet Profits Interests in gas properties are periodically assessed to determinewhether their net capitalized cost is impaired. The Trust will determine if awritedown is necessary to its investment in the Net Profits Interests in gasproperties to the extent that total capitalized costs, less accumulated amortization,exceed undiscounted future net revenues attributable to proved gas reserves ofthe Underlying Properties. The Trust will then provide a writedown to theextent that 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.

Significantdispositions or abandonment of the Underlying Properties are charged to NetProfits Interests and the Trust Corpus.

Amortizationof the Net Profits Interests in gas properties is calculated on aunits-of-production basis, whereby the Trust’s cost basis in the properties isdivided by total Trust proved reserves to derive an amortization rate per reserveunit. Such amortization does not reduce Distributable Income, rather it ischarged directly to Trust Corpus. Revisions to estimated futureunits-of-production are treated on a prospective basis beginning on the datesignificant revisions are known.

Theconveyance of the Royalty and Term Interests to the Trust was accounted for asa purchase transaction. The $93,162,180 reflected in the Statements of Assets,Liabilities and Trust Corpus as Net Profits Interests in Gas Propertiesrepresents 5,900,000 Trust Units valued at $20.50 per depository unit less the$27,787,820 paid for Treasury obligations. The carrying value of the Trust’sinvestment in the Royalty Interests is not necessarily indicative of the fairvalue of such Royalty Interests.

*Revenuesand Expenses:*

TheTrust serves as a pass-through entity, with items of depletion, interest incomeand expense, and income tax attributes being based upon the status and electionof the Unitholders. 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.

TheTrust uses the accrual basis to recognize revenue, with royalty income recordedas reserves are extracted from the Underlying Properties and sold. Expenses arealso recognized on an accrual basis. Operating expenses which include Taxes on Propertyand Production and Operating Cost Charges are recognized as incurred pursuantto the Conveyances on a per well production basis. The payment provisions ofthe Gas Purchase Contract between the Trust and Eastern Marketing Corporation (“EasternMarketing”), a wholly owned subsidiary of Eastern American, require paymentwith respect to gas production for a calendar

F-8

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EASTERN AMERICANNATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS

quarterto be made to the Trust on or before the tenth day of the third month followingsuch quarter.

*Use ofEstimates in the Preparation of Financial Statements:*

Thepreparation of financial statements requires the Trust to make estimates andassumptions that affect the reported amounts of assets and liabilities and thereported amounts of revenues and expenses during the reporting period. Actualresults could differ from those estimates.

*SegmentInformation:*

In 1998, the Trustadopted Statement of Financial Accounting Standards No. 131, “Disclosure aboutSegments 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:

Taxcounsel to Eastern American advised Eastern American at the time of formationthat, under then current tax laws, the Trust would be classified as a grantortrust for federal and state income tax purposes and, therefore, would not besubject to taxation at the Trust level. The Trust continues to be tax exempt.Accordingly, no provision for federal or state income taxes has been made.However, the opinion of tax counsel is not binding on taxing authorities.

TheUnitholders are considered, for income tax purposes, to own the Trust’s incomeand principal as though no trust were in existence. Thus, the taxable year forreporting a Unitholder’s share of the Trust income, expense and credits arecontrolled by the Unitholder’s taxable year and method of accounting, not thetaxable year and method of accounting employed by the Trust.

4.             Distributions to Unitholders:

TheTrustee determines for each quarter the amount available for distribution tothe Unitholders. Such amount will be equal to the excess, if any, of the cashreceived by the Trust, on or before the tenth day of the third month followingthe end of each calendar quarter ending prior to the dissolution of the Trust,from the Net Profits Interests then held by the Trust attributable to productionduring such quarter, plus, with certain exceptions, any other cash receipts ofthe Trust during such quarter, over the liabilities of the Trust paid duringsuch quarter, subject to adjustments for changes made by the Trustee duringsuch quarter in any cash reserves established at the discretion of the Trusteefor the payment of contingent or future obligations of the Trust. Cash receivedby the Trustee in a particular quarter from the Net Profits Interests willreflect actual gas production for a portion of such quarter and a productionestimate for the remainder of such quarter, such estimate to be adjusted toactual production in the following quarter. In accordance with the TrustAgreement and Delaware law, Unitholders should be shielded from directliability for any environmental liabilities. However, costs and expensesincurred 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.

NetProceeds Receivable included in the Statements of Assets, Liabilities and TrustCorpus as of December 31, 2006 are expected to be received by the Trust anddistributed to the Unitholders on March 15, 2007. The December 31, 2005 NetProceeds Receivable were received and distributed by the Trust on March 15,2006.

5.             Related Party Transactions:

TheTrust is responsible for paying all legal, accounting, engineering and stockexchange fees, printing costs and other administrative expenses incurred at thedirection of the Trustee. The total of all Trustee fees and Trustadministrative expenses was $1,317,881 for the year ended December 31, 2006,$1,474,570 for the year ended December 31, 2005, and $695,805 for the yearended December 31, 2004. In accordance with the Trust Agreement, the Trusteepays Eastern American an annual fee which increases by 3.5% per year, payablequarterly, to reimburse Eastern American for overhead expenses. The initial feeat the inception of the Trust was $210,000. The Trustee paid Eastern American$328,432, $317,324 and $306,592 for overhead expenses for 2006, 2005 and 2004respectively. Operating Cost Charges included in the Statements ofDistributable Income are paid to Eastern American.

Gasproduction attributable to the Net Profits Interests is purchased from theTrust by Eastern Marketing pursuant to a Gas Purchase Contract, whicheffectively commenced as of January 1, 1993 and expires upon the termination ofthe Trust.

Pursuantto the Gas Purchase Contract, Eastern Marketing is obligated to purchase suchgas production at a purchase price per Mcf equal to the greater of the IndexPrice, as defined below, or a Floor Price, for gas produced in any quarterduring the

F-9

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EASTERN AMERICANNATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS

PrimaryTerm, 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.

TheIndex Price for any quarter subsequent to the Primary Term, which expiredDecember 31, 1999, is determined solely by reference to the Variable Pricecomponent. The Variable Price for any quarter is equal to the Henry Hub AverageSpot Price (as defined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% toeffect a fixed adjustment for Btu content. The Henry Hub Average Spot Price isdefined as the price per MMBtu determined for any calendar quarter equal to theprice obtained with respect to each of the three months in such quarter, in themanner specified below, and then taking the average of the prices determinedfor each of such three months. The price determined for any month of suchquarter is equal to the average of (i) the final settlement prices per MMBtufor Henry Hub Gas Futures Contracts (as defined), as reported in *The Wall Street Journal,*for such contracts which expired ineach of the five months prior to such month, (ii) the final settlement priceper 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 determined as of the contract settlement date forsuch month, as reported in *The Wall Street Journal,*forsuch contracts which expire in each of the six months following such month. AHenry Hub Gas Futures Contract is defined as a gas futures contract for gas tobe delivered to the Henry Hub which is traded on the New York MercantileExchange.

Undera standby performance agreement Eastern American has agreed to make paymentsunder the Gas Purchase Contract to the extent such payments are not made byEastern Marketing.

F-10

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Supplemental Reserve Information (Unaudited):

Informationregarding estimates of the proved gas reserves attributable to the Trust arebased on reports prepared by independent petroleum engineering consultants.Such estimates 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 to changeas additional information becomes available.

Thereserves actually recovered and the timing of production of these reserves maybe substantially different from the original estimates.

Thestandardized measure of discounted future net cash flows was determined basedon reserve estimates prepared by the independent petroleum engineeringconsultants. Fixed gas prices were used during the Primary Term, which endedDecember 31, 1999. The gas prices used thereafter are based solely on thefourth quarter Variable Price component.

Thereserves and revenue values for the Underlying Properties transferred to theTrust were estimated from projections of reserves and revenue valuesattributable to the combined Eastern American and Trust interests in theseproperties. Reserve quantities are calculated differently for the Net ProfitsInterests because such interests do not entitle the Trust to a specificquantity of gas but to 90 % of the Net Proceeds derived therefrom. Accordingly,there is no precise method of allocating estimates of the quantities of provedreserves between those held by the Trust and the interests to be retained byEastern American. For purposes of this presentation, the proved reservesattributable to the Net Profits Interests have been proportionately reduced toreflect the future estimated costs and expenses deducted in the calculation ofNet Proceeds with respect to the Net Profits Interests. The reserves presentedfor the Net Profits Interests reflect quantities of gas that are free of futurecosts or expenses. The allocation of proved reserves between the Trust andEastern American will vary in the future as relative estimates of future grossrevenues and future costs and expenses vary.

Theroyalty portion of the Net Profits Interests was calculated beyond theliquidation date of the Trust (May 15, 2013), even though the terms of theTrust Agreement require that the Royalty Net Profits Interest be sold by theTrustee on or about this date and a liquidating distribution from the sales proceedsfrom such sale would be made to the Unitholders. The Term Net Profits Interestswas limited to the 20-year period as defined by the Trust Agreement.

F-11

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Thefollowing table reconciles the change in proved reserves attributable to theTrust’s share of the Net Profits Interests (“NPI”) from January 1, 2004 toDecember 31, 2006:
|                                  | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|----------------------------------|------------|------------------|------------|---------------|------------|----------------|------------|
| ** **                       | ** ** | **(MMcf)**       | ** ** | **(MMcf)**    | ** ** | **(MMcf)**     | ** ** |
|                             |       |             |       |          |       |           |       |
| Balance, January  1, 2004        |       | 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         |       |
|                             |       |             |       |          |       |           |       |
| Production                       |       | (788             | )          | (1,059        | )          | (1,847         | )          |
| Revisions of  previous estimates |       | (593             | )          | (124          | )          | (717           | )          |
|                             |       |             |       |          |       |           |       |
| Balance, December 31,  2006      |       | 9,885            |       | 4,814         |       | 14,699         |       |

 

The Trust’s share ofproved developed gas reserves are as follows:
|                    | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|--------------------|------------|------------------|------------|---------------|------------|----------------|------------|
| ** **         | ** ** | **(MMcf)**       | ** ** | **(MMcf)**    | ** ** | **(MMcf)**     | ** ** |
|               |       |             |       |          |       |           |       |
| December 31,  2004 |       | 11,456           |       | 6,702         |       | 18,158         |       |
|               |       |             |       |          |       |           |       |
| December 31,  2005 |       | 11,266           |       | 5,997         |       | 17,263         |       |
|               |       |             |       |          |       |           |       |
| December 31, 2006  |       | 9,885            |       | 4,814         |       | 14,699         |       |

 

StandardizedMeasure of Discounted Future Net Cash Flows Relating to Proved Reserves:

The following is the standardized measure ofdiscounted future net cash flows as of December 31, 2006 (in thousands):
|                                                           | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|-----------------------------------------------------------|------------|------------------|------------|---------------|------------|----------------|------------|
|                                                      |       |             |       |          |       |           |       |
| Future cash  inflows                                      |       | $                | 96,482     |          | $          | 43,880         |       | $ | 140,362 |   |
| Future  production taxes                                  |       | (4,395           | )          | (1,762        | )          | (6,157         | )          |
| Future  production costs                                  |       | (12,060          | )          | (3,411        | )          | (15,201        | )          |
|                                                      |       |             |       |          |       |           |       |
| Future net cash  inflows                                  |       | 80,027           |       | 38,977        |       | 119,004        |       |
| 10% discount  factor                                      |       | (46,248          | )          | (9,496        | )          | (55,744        | )          |
|                                                      |       |             |       |          |       |           |       |
| Standardized measure of  discounted future net cash flows |       | $                | 33,779     |          | $          | 29,481         |       | $ | 63,260 |   |

 

F-12

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The following is the standardized measure ofdiscounted 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 |   |

 

Thefollowing is the standardized measure of discounted future net cash flows as ofDecember 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 |   |

 

Changesin Standardized Measure of Discounted Future Net Cash Flows:

The following schedulereconciles the changes during 2004, 2005 and 2006 in the standardized measureof discounted future net cash flows relating to proved reserves (in thousands):
|                                           | ** ** | **Royalty  NPI** | ** ** | **Term  NPI** | ** ** | **Total  NPI** | ** ** |
|-------------------------------------------|------------|------------------|------------|---------------|------------|----------------|------------|
|                                      |       |             |       |          |       |           |       |
| Standardized  measure, January 1, 2004    |       | $                | 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                |       | (10,696          | )          | (5,693        | )          | (16,389        | )          |
| 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                                     |       | (1,875           | )          | 4,607         |       | 2,731          |       |
|                                      |       |             |       |          |       |           |       |
| Standardized  measure, December 31, 2005  |       | $                | 59,278     |          | $          | 54,992         |       | $ | 114,270 |   |
| Net proceeds to  the Trust                |       | (10,629          | )          | (5,176        | )          | (15,805        | )          |
| Revisions of  previous estimates          |       | (2,553           | )          | (534          | )          | (3,087         | )          |
| Accretion of  discount                    |       | 5,928            |       | 5,499         |       | 11,427         |       |
| Net change in  price and production costs |       | (24,264          | )          | (11,435       | )          | (35,699        | )          |
| Other                                     |       | 6,019            |       | (13,865       | )          | (7,846         | )          |
|                                      |       |             |       |          |       |           |       |
| Standardized measure,  December 31, 2006  |       | $                | 33,779     |          | $          | 29,481         |       | $ | 63,260 |   |

 

F-13

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QuarterlyFinancial Data (Unaudited):

Thefollowing is a summary of royalty income and distributable income per unit byquarter in 2006, 2005 and 2004 (all amounts in thousands except Distributableincome per unit):
| **2006**                       | ** ** | **Mar 31** | ** ** | **June 30** | ** ** | **Sept 30** | ** ** | **Dec 31** | ** ** | **Total** | ** ** |
|--------------------------------|------------|-----------------|------------|------------------|------------|------------------|------------|-----------------|------------|-----------|------------|
|                           |       |            |       |             |       |             |       |            |       |      |       |
| Royalty income                 |       | $               | 5,363      |             | $          | 4,595            |       | $               | 4,300      |      | $          | 3,406 |   | $ | 17,664 |   |
|                           |       |            |       |             |       |             |       |            |       |      |       |
| Distributable  income          |       | $               | 4,385      |             | $          | 3,780            |       | $               | 3,313      |      | $          | 2,681 |   | $ | 14,159 |   |
|                           |       |            |       |             |       |             |       |            |       |      |       |
| Distributable income  per unit |       | $               | 0.7432     |             | $          | 0.6407           |       | $               | 0.5616     |      | $          | 0.4544 |   | $ | 2.3998 |   |

 
| **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 |   |

 

F-14

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