**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

## **FORM1O-K**

## ** **

| **ý** | ** ** | **ANNUAL REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31,  2004**                                                        |
|------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **OR**     |
| **o**      | ** ** | **TRANSITION REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION**                                                                                   |
| ** ** | ** ** | ** **                                                                                                                                                                                              |
| ** ** | ** ** | **PERIOD  FROM               TO                ** |

 

**Commission file number: 1-11748**

 

## **EasternAmerican Natural Gas Trust**

(Exact name of registrant as specified in its Charter)

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

 

**JPMorgan Chase Bank, Trustee**

**Institutional Trust Services**

**700 Lavaca, 2nd Floor**

**Austin, TX 78701**

 (Address of principal executiveoffice) (Zip Code)

 

**(800) 852-1422**

(Registrant’s telephone number, including area code)

 

 

Securities registered pursuant to Section 12(b) of the Act:

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

 

Securities registered pursuant to Section 12(g) of the Act:

**None**

 

Indicateby check mark whether the registrant (1) has filed all reports required to befiled by Section 13 or 15(d) of the Securities Exchange Act of 1934 duringthe preceding 12 months (or for such shorter period that the registrant wasrequired to file such reports) and (2) has been subject to such filingrequirements for the past 90 days: Yes o No ý(1)

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the bestof the registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or any amendment tothis Form 10-K. ý

 

Indicateby check mark whether the registrant is an accelerated filer (as defined inRule 12b-2 of the Act).  Yes ý  No o

 

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(1)          TheRegistrant inadvertently did not file reports on Form 8-K for its 2004 secondand third quarter press releases announcing quarterly distributable income anddistribution amounts.

 

As of March30, 2005, 5,900,000 Units of Beneficial Interest in Eastern American NaturalGas Trust have been issued, remain outstanding and are held by non-affiliatesof the registrant (the “Outstanding Units”).

 

Theaggregate market value of the Outstanding Units (minus the Withdrawn Units, asdescribed herein) at the closing sales price on June 30, 2004 of $23.37was approximately $138 million.

 

DocumentsIncorporated By Reference:     None

 

 

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**TABLE OF CONTENTS**

 
| **PART I**   | ** ** |
|--------------|------------|
|         |       |   | **Page** |
| Item         | 1.         | Business | 1 |   |
|         |       | Description of the Trust | 1 |   |
|         |       | The Net Profits Interests | 2 |   |
|         |       | The Underlying Properties | 6 |   |
|         |       | Competition and Markets | 8 |   |
|         |       | Regulation of Natural Gas | 8 |   |
|         |       | Health,  Safety and Environmental Regulation | 8 |   |
|         |       | Description  of Trust Units and Depositary Units | 9 |   |
|         |       | Federal Income Tax Matters | 11 |   |
|         |       | State Tax Considerations | 17 |   |
|         |       | Available Information | 18 |   |
| Item         | 2.         | Properties | 18 |   |
| Item         | 3.         | Legal Proceedings | 18 |   |
| Item         | 4.         | Submission of Matters to a  Vote of Unitholders | 18 |   |
|         |       |   |   |   |
| **PART II**  |       |   |
|         |       |   |   |   |
| Item         | 5.         | Market for the Registrant’s  Common Equity, Related Unitholders Matters and Issuer Purchases of Equity  Securities | 19 |   |
| Item         | 6.         | Selected Financial Data | 19 |   |
| Item         | 7.         | Management’s Discussion and  Analysis of Financial Condition and Results of Operations | 19 |   |
| Item         | 7A.        | Quantitative and  Qualitative Disclosure About Market Risk | 23 |   |
| Item         | 8.         | Financial Statements and  Supplementary Data | 23 |   |
| Item         | 9.         | Changes in and  Disagreements with Accountants on Accounting and Financial Disclosure | 24 |   |
| Item         | 9A.        | Controls  and Procedures | 24 |   |
| Item         | 9B.        | Other  Information | 25 |   |
| **PART III** |       |   |
|         |       |   |   |   |
| Item         | 10.        | Directors  and Executive Officers of the Registrant | 25 |   |
| Item         | 11.        | Executive  Compensation | 26 |   |
| Item         | 12.        | Security  Ownership of Certain Beneficial Owners and Management | 26 |   |
|         |       |   |   |   |
| Item         | 13.        | Certain  Relationships and Related Transactions | 26 |   |
| Item         | 14.        | Principal  Accounting Fees and Services | 26 |   |
| **PART IV**  |       |   |
|         |       |   |   |   |
| Item         | 15.        | Exhibits,  Financial Statement Schedules | 27 |   |
|         |       |   |   |   |
| SIGNATURES   | 28         |   |

 

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**PART I**

 

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

 

**CautionaryStatement**

** **

TheTrustee (as defined below), its officers or its agents on behalf of the Trusteemay, from time to time, make forward-looking statements (other than statementsof historical fact).  In addition, thisReport on Form 10-K may contain forward-looking statements.  When used herein, the words “anticipates,” “expects,”“believes,” “intends” or “projects” and similar expressions are intended toidentify forward-looking statements.  Tothe extent that any forward-looking statements are made, the Trustee is unableto predict future changes in gas prices, gas production levels, economicactivity, legislation and regulation, and certain changes in expenses of theTrust (as defined below).  In addition,the Trust’s future results of operations and other forward looking statementscontained in this item and elsewhere in this report involve a number of risksand uncertainties.  As a result ofvariations in such factors, actual results may differ materially from anyforward-looking statements.  Some ofthese 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**

 

Asused herein, the following terms have the meanings indicated: “Mcf” meansthousand cubic feet of gas, “MMcf” means million cubic feet of gas, “Bbl” meansbarrel (approximately 42 U.S. gallons), and “MBbl” means thousand barrels, “Btu”means British thermal units and “MMBtu” means million British thermal units.

 

Thefollowing descriptions of the Eastern American Natural Gas Trust (the “Trust”),the Depositary Units, the Net Profits Interests, the Underlying Properties andthe calculation of amounts payable to the Trust, are subject to and qualifiedin their entirety by the more detailed provisions of the Trust Agreement, theDepositary Agreement, the Conveyances and the Gas Purchase Contract (each asdefined below), all of which are incorporated by reference as exhibits to thisForm 10-K and available upon request from JPMorgan Chase Bank, N.A. at theaddress set forth herein.  Theinformation contained herein relating to the operations of the UnderlyingProperties, as well as information upon which the reserve figures and financialinformation contained herein were derived, was furnished to the Trustee byEastern American Energy Corporation (“Eastern American”).

 

**DESCRIPTIONOF THE TRUST**

 

TheTrust was formed under the Delaware Business Trust Act pursuant to a TrustAgreement (the “Trust Agreement”) among 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 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 November 20, 2004, the holders of amajority of the Trust Units voting at a special meeting approved theresignation of The Bank of New York as trustee and depository of the Trust andthe appointment of JPMorgan Chase Bank, N.A. as successor trustee of the Trust.  The appointment of JPMorgan Chase Bank, N.A.as successor trustee became effective as of January 1, 2005.  Consequently, references herein to the “Trustee”mean JPMorgan Chase Bank, N.A. as successor trustee, on and after January 1,2005.  References to the “Trustee” at anytime prior to January 1, 2005 mean The Bank of New York as trustee.  Effective January 1, 2005, the transferagent for the Trust is Bondholder Communications.

 

TheTrust was formed to acquire and hold net profits interests (the “Net ProfitsInterests”) created from the working interests owned by Eastern American in 650producing gas wells and 65 proved development well locations located in WestVirginia and Pennsylvania (the “Underlying Properties”). A portion of theproduction from the wells burdened by the Net Profits Interests was intended tobe eligible for credits (“Section 29 Credits”) under the Internal RevenueCode of 1986 for production of gas from Devonian shale or tight formations. TheNet Profits Interests to be acquired consisted of a royalty interest in 322wells and a term interest in the remaining wells and locations. EasternAmerican was obligated to drill and complete, at its expense, 65 developmentwells (the “Development Wells”) on the development well locations conveyed tothe 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 and prior to or on May 15,2013 (the “Liquidation Date”), the Trustee is required to sell the remainingroyalty interests and

 

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liquidatethe Trust.

 

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

 

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 Underlying Properties (definedbelow) subject to the Net Profits Interests. The Trust Agreement provides,among other things, that: the Trust shall not engage in any business orcommercial activity or acquire any asset other than the Net Profits Interestsinitially conveyed to the Trust; the Trustee may establish a reserve forpayment of any liability which is contingent, uncertain in amount or that isnot currently due and payable; the Trustee is authorized to borrow fundsrequired to pay liabilities of the Trust, provided that such borrowings arerepaid in full prior to further distributions to Unitholders and other  holders of Trust Units (together, “TrustUnitholders”); and the Trustee will make quarterly cash distributions to TrustUnitholders from funds of the Trust.

 

The Trust is responsible for paying the Trustee’s fees and all legal,accounting, engineering and stock exchange fees, printing costs and otheradministrative expenses incurred by or at the direction of the Trustee.  The total fees paid to the Trustee for 2004were $45,000.  The total of all Trusteefees and Trust administrative expenses for 2004 was $695,805.  Such costs could fluctuate in the futuredepending primarily on the expenses the Trust incurs for professional services,particularly legal, accounting and engineering services.  In addition to such expenses, in 2004, theTrust paid Eastern American an overhead reimbursement of $306,592.  The overhead reimbursement increases by 3.5%per year and is payable quarterly.

 

On December 8, 2004 the Trust announced approval by the TrustUnitholders of a proposal to elect JPMorgan Chase to serve as successor trusteeof the Trust upon the effective date of the resignation of The Bank of New Yorkas trustee of and depositary for the Trust and to amend the Trust Agreement tochange the compensation of the Trustee. The resignation of The Bank of New York took effect on January 1,2005.  As successor trustee, JPMorganChase will receive annual compensation of $108,000, plus fees and expenses.

 

###### **THENET PROFITS INTERESTS**

###### ** **

**The Conveyances**

 

TheNet Profits Interests (“NPI”) were created from the Underlying Properties andconveyed to the Trust pursuant to two Conveyances - one conveying a royaltyinterest in specified wells (the “Royalty NPI Conveyance”) and the otherconveying the a term interest in specified wells (the “Term NPI Conveyance”,and together with the Royalty NPI Conveyance, the “Conveyances”). Forms of theConveyances have been incorporated by reference as exhibits to this report.

 

TheUnderlying Properties are subject to and burdened by the Net Profits Interests.The interests of Eastern American comprising the Underlying Propertiesrepresent, on average, a working interest of approximately 90% and a netrevenue interest of approximately 76%. The Conveyances provide that the Trustis only entitled to gas produced from the specific wells identified in theConveyances and is not entitled to any gas produced from adjacent wells(including adjacent wells subject to the same lease or farmout agreement as thewells subject to the Net Profits Interests). Gas produced from the UnderlyingProperties which is attributable to the Net Profits Interests is purchased fromthe Trust by Eastern Marketing Corporation, a wholly-owned subsidiary ofEastern American (“Eastern Marketing”) pursuant to a gas purchase contract (the“Gas Purchase Contract”). The volumes attributable to the Net Profits Interestsand the purchase 

 

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pricefor such gas is calculated for each calendar quarter, and payment for such gasis made to the Trust not later than the 10th day of the third calendar monthfollowing the end of each calendar quarter.

 

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 31,2004, 20,706 MMcf of such gas had been 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 UnderlyingProperties and require the Trust to release the NPI burdening that property,without the consent of the Trustee or Unitholders, subject to payment to theTrust of the fair value of the interest released. In addition, any abandonmentof a well included in the Underlying Properties or the Development Wells willextinguish that portion of the Net Profits Interests that relate to suchwell.  See “Sale and Abandonment ofUnderlying Properties; Sale of Royalty NPI.”

 

**Calculationof Net Proceeds**

 

Thedefinitions, formulas, accounting procedures and other terms governing thecomputation of Net Proceeds are detailed and extensive, and reference is madeto both the Royalty NPI Conveyance and the Term NPI Conveyance for a moredetailed discussion of the computation thereof.

 

TheConveyances and the Gas Purchase Contract entitle the Trust to receive anamount of cash for each calendar quarter equal to the Net Proceeds for suchquarter.  “Net Proceeds” for any calendarquarter generally means an amount of cash equal to (a) 90% of a volume of gasequal 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 for suchquarter under the Gas Purchase Contract. If, for any reason, the Gas PurchaseContract terminates prior to the Liquidation Date, “Net Proceeds” will mean anamount of cash equal to (a) 90% of a volume of gas equal to (i) the volume ofgas produced during such quarter attributable to the Underlying Properties less(ii) a volume of gas equal to Chargeable Costs for such quarter, multiplied by(b) the applicable price for such quarter determined in accordance with theConveyances. Pursuant to the Conveyances, the Trust is not entitled to receiveany natural gas liquids produced from the Underlying Properties or any proceedsrelating thereto.

 

 “Chargeable Costs” is that volume of gas whichequates in value, determined by reference to the relevant sales price under theGas Purchase Contract or the Conveyances, as applicable, to the sum of the “OperatingCost Charge”, “Capital Costs” and “Taxes” (as defined in the Conveyances).   The Operating Cost Charge for 2004 was$519,228, for 2003 was $510,032 and for 2002 was $501,738.  As provided in the Conveyances, the OperatingCost Charge will increase based on the lesser of (A) five percent (5%) or (B) apercentage, not less than zero percent (0%), equal to the percentage increase,if any, in the average weekly earnings of Crude Petroleum and Gas ProductionWorkers for the last calendar year, as shown by the index of average weeklyearnings of Crude Petroleum and Gas Production Workers, as published by theUnited States Department of Labor, Bureau of Labor Statistics, based onDecember-to-December comparison.

 

During2003, the United States Department of Labor, Bureau of Labor Statisticsconverted all of its industry-based statistics to a different reporting systemthat was developed in cooperation with the United States’ North American FreeTrade Agreement Partners, Canada and Mexico, in an effort to standardize andmodernize reporting codes.  As a resultof this conversion, the Crude Petroleum and Gas Production Workers index is nolonger available for use in the annual calculation of overhead adjustmentcalled for in the various Council of Petroleum Accountants Societies, or COPAS,model forms after March 2003.

 

Research by COPAS covering the past ten yearsindicated that by blending the Oil and Gas Extraction Index with theProfessional and Technical Services Index, the results approximate the datafrom the old Crude Petroleum and Natural Gas Workers Index. Accordingly, COPAShas calculated the percentage change in the simple average of the Oil andExtraction Index and the Professional and Technical Services Index, commencingin April 2004. This “Overhead Adjustment Index” has been provided as a guidance to the industry as a replacement index for use incalculating the overhead adjustment. The adjustment for the effective timeperiod is 2.3%. Since the

 

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Conveyance Documents do not specifically providefor a replacement index if the Crude Petroleum and Gas Production Workers Indexwas no longer published, Eastern American believes,and advised the Trustee, that the “Overhead Adjustment Index” as calculated byCOPAS is a reasonable index to utilize since the industry is generally adoptingthe same as a replacement. Eastern American, with the concurrence of theTrustee, will utilize this “Overhead Adjustment Index” to adjust the “OperatingCost Charge” so long as such index is published by COPAS.

 

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

 

Although the Trust bears the full economic burden of Chargeable Costs,it does so indirectly in the calculation of Net Proceeds and the Trust is notdirectly liable for any share of the costs, risks, and liabilities associatedwith the ownership or operation of the Underlying Properties. If the Trust everreceives payments in excess of the Net Proceeds or other amounts it was notentitled to receive, the Trust will not be required to refund the money, butEastern American may recover the amount of such overpayments from futuredistributions in accordance with the Conveyances.

 

TheConveyances require Eastern American to maintain books, records, and accountssufficient to calculate the volumes of gas and the share of Net Proceedspayable to the Trust. Eastern American provides to the Trust quarterly andannual statements of applicable production, revenues, and costs necessary forthe Trust to prepare quarterly and annual financial statements with respect tothe Net Profits Interests and the Underlying Properties. The financialstatements of the Trust are audited annually at the Trust’s expense.

 

**GasPurchase Contract**

 

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

 

Underthe Gas Purchase Contract, Eastern Marketing purchases gas from the Trust at avariable price for each quarter equal to the Henry Hub Average Spot Price (asdefined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixedadjustment for Btu content. The Henry Hub Average Spot Price is defined as theprice per MMBtu determined for any calendar quarter equal to the price obtainedwith respect to each of the three months in such quarter, in the mannerspecified below, and then taking the average of the prices determined for eachof such three months. The price determined for any month of such quarter isequal to the average of (i) the final settlement prices per MMBtu for Henry HubGas Futures Contracts (as defined), as reported in *The WallStreet Journal,*for such contracts which expired in each of the fivemonths prior to such month, (ii) the final settlement price per MMBtu for HenryHub Gas Futures Contracts, as reported in *The Wall Street Journal,*forsuch contracts which expire during such month and (iii) the closing settlementprices per MMBtu of Henry Hub Gas Futures Contracts determined as of thecontract settlement date for such month, as reported in *The WallStreet Journal,*for such contracts which expire in each of the sixmonths following such month.  A Henry HubGas Futures Contract is defined as a gas futures contract for gas to bedelivered to the Henry Hub, which is traded on the New York MercantileExchange.

 

The purchase price paid to the Trust pursuant to the Gas PurchaseContract is a wellhead price and title to the gas purchased pursuant to the GasPurchase Contract passes to Eastern Marketing at the point of delivery.  Payments to the Trust for gas purchasedpursuant to the Gas Purchase Contract are made by Eastern Marketing on orbefore the tenth day of the third calendar month following the end of eachcalendar quarter.

 

TheTrust Agreement provides that the Trustee may not agree to any amendment to theGas Purchase Contract which would materially and adversely affect the revenuesto the Trust without the approval of the holders of a majority of theoutstanding Trust Units. The Trust Agreement also provides that the GasPurchase Contract may not be terminated by the Trust without the approval ofthe holders of a majority of the outstanding Trust Units. The Gas PurchaseContract and the Trust Agreement have been filed as exhibits to this Form10-K.  The foregoing summary of theprincipal provisions of the Gas Purchase Contract, and certain provisions ofthe Trust Agreement, is qualified in its entirety by reference to the terms ofsuch agreements as set forth in such exhibits.

 

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EasternMarketing’s rights and obligations under the Gas Purchase Contract areassignable under circumstances where the assignee unconditionally assumesEastern Marketing’s obligations under the Gas Purchase Contract only if suchassignee (or assignee’s parent corporation if such parent guarantees theassignee’s obligations) has a rating assigned to its unsecured long-term debtby Moody’s Investor Service of at least Baa+ and by Standard & Poor’sCorporation of at least BBB-. Under such circumstances, Eastern Marketing andEastern American would be released from their obligations under the GasPurchase Contract.

 

**PerformanceSupport for Gas Purchase Contract**

 

Gasproduction attributable to the Net Profits Interests will be purchased byEastern Marketing pursuant to the Gas Purchase Contract, which expires upon theLiquidation Date of the Trust.  EasternAmerican has agreed to make payment 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 theamount of cash available for distribution to holders of Depositary Units andthe Trust Units evidenced thereby.  Suchamount (the “Quarterly Distribution Amount”) is equal to the excess, if any, of(i) the cash that the Trust receives on or before the tenth day of the thirdmonth after the end of each calendar quarter ending before the Trust isdissolved and that is attributable to production from the Net Profits Interestheld by the Trust during that calendar quarter, plus, with certain exceptions,any other cash receipts of the Trust during such quarter, over (ii) theliabilities of the Trust paid during such quarter, subject to adjustments forchanges made by the Trustee during such quarter in any cash reservesestablished for the payment of contingent or future obligations of theTrust.  Quarterly Distribution Amountsfor each of the quarters in 2004 were $0.43, $0.49, $0.48, and $0.62 respectively.Based on the payment procedures relating to the Net Profits Interests, cashreceived by the Trustee in a particular quarter from the Net Profits Interestsreflects 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. The Quarterly Distribution Amount for each quarter is payable toUnitholders of record on the last day of the second month following the end ofsuch calendar quarter or such later date as the Trustee determines is requiredto comply with legal or stock exchange requirements (“Quarterly Record Date”).  It is expected that the Trustee will continueto be able to distribute cash on or before the 15th day (or the next succeedingbusiness day following such day if such day is not a business day) of the thirdmonth following the end of each calendar quarter to each person who was aUnitholder of record on the Quarterly Record Date, together with interestearned on such Quarterly Distribution Amount from the date of receipt thereofby the Trustee to the payment date.

 

Thenet taxable income of the Trust for each calendar quarter is reported by theTrustee for tax purposes as belonging to the holders of record to whom theQuarterly Distribution Amount was or will be distributed. Assuming that theTrust will be classified for tax purposes as a “grantor trust,” the net taxableincome will be realized by the holders for tax purposes in the calendar quarterreceived by the Trustee, rather than in the quarter distributed by the Trustee.Thus, a Unitholder’s taxable income for a taxable year may differ from the cashthe Unitholder receives during that year. In addition, taxable income of aholder will 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 possibilities that a reservewill be established in one quarter that will not give rise to a tax deductionuntil a subsequent quarter, an expenditure paid for in one quarter will have tobe amortized for tax purposes over several quarters, or for other reasons. See “FederalIncome Tax Matters.”

 

Each holder of Depositary Units (including the underlying Trust Units)of record as of the record date for the final quarter of the Trust’s existencewill be entitled to receive a liquidating distribution equal to a pro rataportion of the net proceeds from the sale of the Royalty NPI (to the extent notpreviously distributed) and a pro rata portion of the proceeds from the maturedTreasury Obligations.

 

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

 

Eastern American and any transferees have the right to abandon any wellor working interest included in the Underlying Properties if, in its opinion,such well or property ceases to produce or is not capable of producing incommercially paying quantities. To reduce or eliminate the potential conflictof interest between Eastern American and the Trust in determining whether awell is capable of producing in paying quantities, Eastern American is requiredunder 

 

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the Conveyances tomake any such determination as would a reasonably prudent operator in theAppalachian Basin if it were acting with respect to its own properties,disregarding (i) the existence of the Net Profits Interests as a burden on suchproperty and (ii) the direct or indirect effect, financial or otherwise, onEastern American or any of its affiliates that may result from the performanceby Eastern Marketing of its obligations under the Gas Purchase Contract.

 

Eastern American has the right, pursuant to the Conveyances, to sellall or any portion of the Underlying Properties without restrictions; however,the purchaser of any of the Underlying Properties will acquire such UnderlyingProperties subject to the Net Profits Interests relating thereto (except incertain circumstances described below where the Trust may be required torelease the Net Profits Interests, subject to its receipt of the fair valuethereof). Any such purchaser will be subject to the same standards of conductwith respect to development, operation and abandonment of such UnderlyingProperties as set forth in the preceding paragraph.

 

Eastern American may sell the Underlying Properties, subject to andburdened by the Net Profits Interests, without the consent of the Trust or theUnitholders.  In addition, until January 1,2010, Eastern American can require the Trust to release the Net ProfitsInterests associated with the sale of wells, regardless of number of wellssold, provided that such releases cannot exceed an aggregate value to the Trustof $500,000 during any 12 month period. Sales subsequent to January 1,2010 may be made without regard to dollar limitations. These releases will bemade 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.

 

TheTrustee is required to sell all of the Royalty NPI after May 15, 2012 and priorto the Liquidation Date. The proceeds of such sale, together with the maturedface amount of the Treasury Obligations, will be distributed to Unitholders onor prior to the Liquidation Date. Under the Trust Agreement, Eastern Americanhas a right of first refusal to purchase any of the Royalty NPI at the fairvalue to the Trust, or if applicable the offered third-party price, prior tothe Liquidation Date.

 

**THEUNDERLYING PROPERTIES**

 

**General**

 

TheUnderlying Properties are comprised of Eastern American’s working interests incertain properties located in the Appalachian Basin states of West Virginia andPennsylvania.  As of December 31,2004, such properties consisted of 672 producing gas wells.   The working interests of Eastern Americancomprising the Underlying Properties are held under leases and farmoutagreements with third parties. Such working interests are subject to landowner’sroyalties (typically 12-1/2%) and may be subject to additional royalties orother obligations burdening the working interests. Such royalties do not bearlease operating expenses, but reduce the revenue interests attributable to theUnderlying Properties. Eastern American’s interests comprising the UnderlyingProperties represent, on average, a working interest of approximately 90% and anet revenue interest of approximately 76%.  As of December 31, 2004, proved developed reserves attributable tothe Net Profits Interests (reflecting quantities of gas free of future costsand expenses based on estimated prices) were approximately 18,158 MMcf. (See “Reserves”).

 

 The Appalachian Basin is a mature producingregion with 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.

 

TheUnderlying Properties initially included 65 specified development welllocations for the drilling of the Development Wells by Eastern American.Eastern American was obligated to bear the costs of drilling and completing theDevelopment Wells.  Eastern American hasfulfilled its obligation with respect to the drilling of the DevelopmentWells.  (seeNote 1 of Financial Statements attached hereto)

 

EasternAmerican acquired its interests in the Underlying Properties under or through(i) oil and gas leases granted by the mineral owner directly to EasternAmerican, (ii) assignments of oil and gas leases by the lessee who 

 

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originallyobtained the leases from the mineral owner, (iii) farmout agreements that grantEastern American the right to earn interests in the properties covered by suchagreements by drilling wells and (iv) the acquisitions of oil and gas interestsby Eastern American.

 

Productionfrom the wells to which the Underlying Properties relate is typically subjectto (i) landowner royalties and other burdens and obligations retained under oiland gas leases, (ii) overriding royalty interests and (iii) interests of otherworking interest owners in the wells. The royalty and overriding interestsentitle the holders thereof to a certain percentage of the oil and gas producedfrom the wells or the proceeds therefrom and are generally delivered free ofall expenses of production but may be subject to post-production costs, such asproduction or gathering taxes, costs to treat the gas to render it marketable,and certain transportation or gathering costs. Royalty interests are usuallyreserved by the lessor under an oil and gas lease. Overriding royalty interestsare carved out of a lessee’s share of production under an oil and gas lease andare generally reserved by a predecessor in title or reserved under farmoutagreements.

 

Afarmout agreement is typically an agreement under which a lessee under an oiland gas lease (the “Farmor”) grants to another party the right to drill wellson the tract covered by such lease and to earn certain acreage for drillingsuch wells. In the Appalachian Basin, the Farmor generally receives a welllocation fee and reserves an overriding royalty interest in the wells whichtypically ranges from 3.25% to 6.25%. Farmout agreements typically provide thatwells must be drilled and completed as a condition to a transfer by the Farmorof the interest in the underlying lease.

 

**Reserves**

 

*Proved Reserves of Underlying Properties and NetProfits Interests.***The followingtable sets forth, as of December 31, 2004, certain estimated provedreserves, estimated future net revenues and the discounted present valuethereof attributable to the Underlying Properties, the Royalty NPI and the TermNPI, in each case derived from a report of oil and gas reserves attributable tothe Trust as of December 31, 2004 prepared by Ryder Scott Company (the “ReserveReport”). Proved reserve quantities attributable to the Net Profits Interestsare calculated by subtracting an amount of gas sufficient, if sold at theprices used in preparing the reserve estimates, to pay the future estimatedcosts and expenses deducted in the calculation of Net Proceeds. Accordingly,the reserves attributable to the Net Profits Interests reflect quantities ofgas that are free of future costs or expenses if the price and cost assumptionsset forth in the Reserve Report occur. A decrease in the price assumption, oran increase in the cost assumption used in the Reserve Report would reduce theestimates of proved reserves, future net revenues and discounted future netrevenues, set forth herein and in the Reserve Report.  The Term NPI excludes production beyond theearlier of May 15, 2013 or such time as 41,683 MMcf of gas has been producedwhich is attributable to Eastern American’s net revenue interests in theproperties burdened by the Term NPI. The discounted present value of estimatedfuture net revenues was determined using a discount rate of 10% in accordancewith applicable requirements. A copy of the Reserve Report is included asExhibit A hereto.

 
| ** **               | ** ** | ** **              | ** ** | ** **      | ** ** | ** **     | ** ** | ** **                 | ** ** | **Discounted**  | ** ** |
|--------------------------|------------|-------------------------|------------|-----------------|------------|----------------|------------|----------------------------|------------|-----------------|------------|
| ** **               | ** ** | **Proved Gas Reserves** | ** ** | **Estimated**   | ** ** | **Estimated**  | ** ** |
| ** **               | ** ** | **(MMcf)**              | ** ** | **Future Net**  | ** ** | **Future Net** | ** ** |
| ** **               | ** ** | **Developed**           | ** ** | **Undeveloped** | ** ** | **Total**      | ** ** | **Revenues(2)**            | ** ** | **Revenues(2)** | ** ** |
| ** **               | ** ** | ** **              | ** ** | ** **      | ** ** | ** **     | ** ** | **(Dollars in thousands)** | ** ** |
|                     |       |                    |       |            |       |           |       |                       |       |            |       |
| Underlying Properties(1) |       | 36,328                  |       | 0               |       | 36,328         |       | $                          | 244,990    |            | $          | 99,361 |   |
|                     |       |                    |       |            |       |           |       |                       |       |            |       |
| Net Profits Interests:   |       |                    |       |            |       |           |       |                       |       |            |       |
| Royalty NPI              |       | 11,456                  |       | 0               |       | 11,456         |       | $                          | 91,886     |            | $          | 38,406 |   |
| Term NPI                 |       | 6,702                   |       | 0               |       | 6,702          |       | 53,758                     |       | 37,790          |       |
|                     |       |                    |       |            |       |           |       |                       |       |            |       |
| Total                    |       | 18,158                  |       | 0               |       | 18,158         |       | $                          | 145,644    |            | $          | 76,196 |   |

 

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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.

 

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(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 Depositary Units and the Trust Units evidenced therebyare substantially dependent upon the proved reserves and production levelsattributable to the Net Profits Interests. There are many uncertaintiesinherent in estimating quantities and values of proved reserves and inprojecting future rates of production and the timing of developmentexpenditures, if any. The reserve data set forth herein, although prepared byindependent engineers in a manner customary in the industry, are estimatesonly, and actual quantities and values of gas are likely to differ from theestimated amounts set forth herein. In addition, the discounted present valuesshown herein were prepared using guidelines established by the Securities andExchange Commission (the “Commission”) and Financial Accounting Standards Boardfor disclosure of reserves and should not be considered representative of themarket value of such reserves or the Depositary Units or the Trust Unitsevidenced thereby. A market value determination would include many additionalfactors.

 

**COMPETITIONAND MARKETS**

 

All ofthe production attributable to the Net Profits Interest is sold to EasternMarketing pursuant to the Gas Purchase Contract.  See “The Net Profits Interests - Gas PurchaseContract.”

 

**REGULATIONOF NATURAL GAS**

 

Thenatural gas industry has historically been highly regulated by state andfederal authorities.  In the past,concerns about perceived pipeline monopolies and other factors caused Congressto impose economic regulation on both pipelines and producers.  Federal agencies regulated tariffs andconditions of service offered by interstate pipelines, and set maximum priceson the wellhead price of natural gas sold into interstate commerce.  States, and even local governments, alsoregulated retail sales of natural gas by local utilities.  Government agencies also set production ratesto avoid waste and imposed environmental and safety regulations.  At present, it appears that Federalregulation of wellhead natural gas prices has ended.   However there can be no assurance that pricecontrols or other similar economic regulations may not be reimposed in thefuture.

 

Drillingand production of natural gas are heavily regulated in Pennsylvania and WestVirginia, as in most states. A well cannot be drilled without a permit, andoperations must be conducted in compliance with environmental, safety andconservation laws and regulations. In contrast to many other states which havesubstantial oil and gas production activity, the spacing of shallow wells (suchas the wells subject to the Net Profits Interests) is not regulated by anystate statute or regulatory agency in either West Virginia or Pennsylvania.Without spacing requirements specified by state statute or regulation, drainageof reserves from a property may occur from wells located in close proximity tosuch property.

 

**HEALTH, SAFETY, AND ENVIRONMENTALREGULATION**

 

*General.***Activities on the Underlying Properties are subject toexisting Federal, state and local laws and regulations governing health,safety, environmental quality and pollution control. It is anticipated that,absent the occurrence of an extraordinary event, compliance with existingFederal, state and local laws, rules and regulations regulating health, safety,the discharge of materials into the environment or otherwise relating to theprotection of the environment will not have a material adverse effect upon theTrust.  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 the Underlying Properties could haveon the Trust. However, pursuant to the terms of the Conveyances, any costs orexpenses incurred in connection with environmental liabilities of EasternAmerican arising out of or related to activities occurring on or in, orconditions existing on or under, the Underlying Properties before the effectivedate of the Conveyances will be borne by Eastern American and will not bededucted in calculating Net Proceeds attributable to the Net Profits Interests.Additionally, because Unitholders will have limited liability in accordancewith the Trust Agreement and Delaware law, Unitholders should be shielded fromdirect liability for any environmental liabilities. See “Description of TrustUnits and Depositary Units—Liability of Unitholders.” However, costs andexpenses incurred by Eastern American for certain Capital Costs associated withenvironmental liabilities arising after the effective date of the Conveyanceswould reduce Net Proceeds, and would therefore be borne, in part, by theUnitholders.  The following subtopicsdiscuss some of the principal forms of health, safety, and 

 

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environmentalregulation to which the Underlying Properties and operations thereon aresubject.  The costs of complying withthese regulatory requirements may burden the Net Profits Interests to theextent they arise out of or are related to activities occurring on or in, orconditions existing on or under, the Underlying Properties after the effectivedate of the Conveyances.

 

*Solid and Hazardous Waste.***The Underlying Properties include numerous properties thathave produced gas for a number of years but in which Eastern American has heldan interest for a relatively short period of time prior to the effective dateof the Conveyances. Eastern American has informed us they have no knowledge ofprior operators utilizing operating and disposal practices that were notstandard in the industry at the time nor have hydrocarbons or other solid orhazardous wastes may have been disposed of or released on or under theUnderlying Properties. Federal, state and local laws applicable to gas-relatedwastes have become increasingly more stringent. Under current laws, EasternAmerican or the operator of the Underlying Properties could be required toremove or remediate previously disposed wastes or property contamination(including groundwater contamination) or to perform remedial pluggingoperations to prevent future contamination.

 

Theoperations of the Underlying Properties may generate wastes that are subject tothe Federal Resource Conservation and Recovery Act (“RCRA”) and comparablestate statutes. The Environmental Protection Agency (the “EPA”) has limited thedisposal options for certain hazardous wastes and may adopt more stringentdisposal standards for nonhazardous wastes.

 

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

 

*Air Emissions.***The operations of the Underlying Properties are subject toFederal, state and local regulations concerning the control of emissions fromsources of air contaminants. Administrative enforcement actions for failure tocomply strictly with air regulations or permits are generally resolved bypayment of a monetary penalty and correction of any identified deficiencies.Regulatory agencies could require the operators to forego or modifyconstruction or operation of certain air emission sources.

 

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

 

**DESCRIPTION OF TRUST UNITS ANDDEPOSITARY UNITS**

 

Thefollowing information is subject to the detailed provisions of the DepositAgreement originally entered into by Eastern American, the Trustee, and Bank ofMontreal Trust Company, as Depositary (the “Depositary”) and all holders fromtime to time of Depositary Units (the “Deposit Agreement”), a copy of which isfiled as an exhibit to this Form 10-K.

 

Thefunctions of the Depositary under the Deposit Agreement are custodial andministerial in nature and for the benefit of Unitholders. The Deposit Agreementand the issuance of Depositary Units thereunder provide Unitholders anadministratively convenient form of holding an investment in the Trust and aTreasury Obligation. Each Depositary Unit is evidenced by a certificate, whichis issued by the Depositary and transferable only in denominations of 50Depositary Units or an integral multiple thereof. Accordingly, each holder of50 Depositary Units owns a beneficial interest in 50 

 

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Trust Units and theentire beneficial interest in a discrete Treasury Obligation in a face amountof $1,000, or $20 per Depositary Unit.

 

Thedeposited Trust Units and Treasury Obligations are held solely for the benefitof the Unitholders and do not constitute assets of the 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 are entitled to participate in distributionswith respect to the Trust Units, the Treasury Obligations and to theliquidation of the remaining assets of the Trust.

 

**Withdrawalof Trust Units and Restrictions on Transfer**

 

Uponpresentation of Depositary Units in denominations of 50 or integral multiplesthereof for withdrawal of the Trust Units and discrete Treasury Obligationsevidenced thereby in accordance with the Deposit Agreement, the Unitholder willreceive an uncertificated direct interest in Trust Units. These withdrawn TrustUnits will be evidenced on the books of the Trustee by a transfer of such TrustUnits from the name of the Depositary to the name of the withdrawingUnitholder. Holders of withdrawn Trust Units will be entitled to receive Trustdistributions and periodic Trust information (including tax information)directly from the Trustee. Moreover, holders of Trust Units will be entitled toeach of the rights accorded Unitholders under the Trust Agreement, includingvoting and liquidation rights, as elsewhere described herein, except thatwithdrawn Trust Units are not freely transferable as described below.

 

Pursuantto the Trust Agreement and the transfer application for transfer of the TrustUnits, withdrawn Trust Units are not transferable except by operation of law. Aholder of withdrawn Trust Units may, however, transfer such Trust Units indenominations of 50 (or integral multiples thereof) to the Depositary forredeposit, together with Treasury Obligations in the face amount equal to$1,000 for each 50 Trust Units redeposited, in exchange for Depositary Units.Such redeposit may be effected by delivering written notice of such transferjointly to the Depositary and the Trustee together with proper documentationnecessary to transfer the requisite Treasury Obligations into the name of theDepositary.

 

**Distributionsand Income Computations**

 

TheTrustee determines for each quarter the Quarterly Distribution Amount availablefor distribution to holders of Depositary Units and the Trust Units evidencedthereby. The Quarterly Distribution Amount is equal to the excess, if any, (i)the cash that the Trust receives on or before the tenth day of the third monthafter the end of each calendar quarter ending before the Trust is dissolved andthat is attributable to production from the Net Profits Interest held by theTrust during that calendar quarter, plus, with certain exceptions, any othercash receipts of the Trust during such quarter, over (ii) the liabilities forthe Trust paid during such quarter, subject to adjustments for changes made bythe Trustee during such quarter in any cash reserves established for thepayment of contingent or future obligations of the Trust. Based on the payment proceduresrelating to the Net Profits Interests, cash received by the Trustee in aparticular quarter from the Net Profits Interests reflects actual gasproduction 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 Quarterly Record Date, which is thelast day of the second month following the end of such calendar quarter or suchlater date as the Trustee determines is required to comply with legal or stockexchange requirements. The Trustee generally is able to distribute cash on orbefore the 15th day (or the next succeeding business day following such day ifsuch day is not a business day) of the third month following the end of eachcalendar quarter to each person who was a Unitholder of record on the QuarterlyRecord Date, together with interest earned on such Quarterly DistributionAmount from the date of receipt thereof by the Trustee to the payment date.

 

The net taxable income of the Trust for each calendar quarter isreported by the Trustee for tax purposes as belonging to the holders of recordto whom the Quarterly Distribution Amount was or will be distributed. Assumingthat the Trust will be classified for tax purposes as a “grantor trust,” thenet taxable income will be realized by the holders for tax purposes in thecalendar quarter received by the Trustee, rather than in the quarter distributedby the Trustee. Taxable income of a holder may differ from the QuarterlyDistribution Amount because the Treasury Obligations will be treated asgenerating interest income for tax purposes. There may also be minor variances because of the possibility that, forexample, a reserve will be established in one quarter that will not give riseto a tax deduction until a subsequent quarter, 

 

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anexpenditure paid for in one quarter will have to be amortized for tax purposesover several quarters.  See “FederalIncome Tax Matters”.

 

Eachholder of Depositary Units (including the underlying Trust Units) of record asof the record date for the final quarter of the Trust’s existence will beentitled to receive a liquidating distribution equal to a pro rata portion ofthe net proceeds from the sale of the Royalty NPI (to the extent not previouslydistributed) and a pro rata portion of the proceeds from the matured TreasuryObligations.

 

**PossibleDivestiture of Depositary Units and Trust Units**

 

The Trust Agreement imposes no restrictions based on nationality orother status of holders of Trust Units. However, the Trust Agreement and the Deposit Agreement provide that inthe 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**

 

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 a court would give effect to such limitation.

 

**Liquidationof the Trust**

 

TheTrust will be liquidated and the Royalty NPI will be sold prior to theLiquidation Date. Unitholders of record as of the record date for the finalquarter of the Trust’s existence will be entitled to receive a terminatingdistribution with respect to each Depositary Unit equal to a pro rata portionof the net proceeds from the sale of the Royalty NPI (to the extent notpreviously distributed) and a pro rata portion of the proceeds from the maturedTreasury Obligations. Under the Trust Agreement, Eastern American has a rightof first refusal to purchase the Royalty NPI at fair market value, or ifapplicable the offered third-party price, prior to the Liquidation Date.

 

**FEDERALINCOME TAX MATTERS**

 

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

 

Thissummary is based on current provisions of the Internal Revenue Code of 1986, asamended (the “Code”), existing and proposed regulations thereunder and currentadministrative rulings and court decisions, all of which are 

 

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subjectto changes that may or may not be retroactively applied. Some of the applicableprovisions of the Code have not been interpreted by the courts or the InternalRevenue Service (“IRS”).

 

At theissuance of the Depositary Units, Eastern American obtained an opinion ofcounsel for the benefit of the Trust, based on certain representations and subjectto certain qualifications, that, for Federal income tax purposes, (a) the Trustwill be taxed as a grantor trust and not as an association taxable as acorporation, (b) the Term NPI will be taxed as a production payment, (c) theincome from the Royalty NPI will be royalty income subject to the allowance fordepletion, and (d) a Unitholder will be eligible to claim Section 29Credits with respect to certain sales of gas production attributable to theRoyalty NPI.  The Trustee has reportedthe operations of the Trust consistent with these opinions.

 

Noruling has been or will be requested from the IRS with respect to any matteraffecting the Trust or Unitholders, and thus no assurance can be provided thatthe statements set forth herein (which do not bind the IRS or the courts) willnot be challenged by the IRS or will be sustained by a court if so challenged.

 

**Reports**

 

Unitholdersof record are provided informational tax packages in order to permitcomputation of their taxable income from ownership of Depositary Units.

 

**Treatmentof Depositary Units**

 

Purchasersof Depositary Units are treated, for Federal income tax purposes, as purchasingdirectly an interest in the Treasury Obligations and a Trust Unit. Purchasersare therefore required to allocate the purchase price of their Depositary Unitbetween the interest in the Treasury Obligations and the Trust Unit in theproportion that the fair market value of each bears to the fair market value ofthe Depositary Unit. Information regarding purchase price allocations isfurnished to Unitholders by the Trustee.

 

**Classificationand Taxation of the Trust**

 

Forfederal income tax purposes, the Trust has been treated and expects to continueto be treated not as an association taxable as a corporation, but as a grantor trust that is not subject to Federal income tax asan entity separate from its beneficial owners. For tax purposes, Unitholders are considered to own and receive theTrust’s assets and income as though no trust were in existence. The Trust filesan information return, reporting all items of income, credit or deduction whichmust be included in the tax returns of the Unitholders. If the Trust weredetermined not to be a grantor trust, it is expected that it would be treatedeither as a partnership subject to the publicly traded partnership rules underthe Code or as an association taxable as a corporation.  If the Trust were treated as a publiclytraded partnership, it is believed that the Trust’s various items of income anddeduction would still be taxable to the Unitholders on a current, flow-throughbasis as partners of a partnership and not to the Trust as an associationtaxable as a corporation.  If the Trustwere determined to be an association taxable as a corporation, it would betreated as a separate entity subject to corporate tax on its taxable income,Unitholders would be treated as shareholders, and distributions to Unitholdersfrom the Trust would be treated as nondeductible corporate distributions. Suchdistributions would be taxable to a Unitholder, first, as dividends to theextent of the Unitholder’s pro rata share of the Trust’s earnings and profits,then as a tax-free return of capital to the extent of his basis in his TrustUnits, and finally as capital gain to the extent of any excess.

 

**DirectTaxation of Unitholders**

 

Assuming that the Trust is treated as a grantor trust for Federalincome tax purposes, and Unitholders are treated for Federal income taxpurposes as owning a direct interest in the Treasury Obligations and the assetsof the Trust, each Unitholder is taxed directly on his pro rata share of theincome attributable to the Treasury Obligations and the assets of the Trust andis entitled to claim his pro rata share of the deductions and creditsattributable to the Trust (subject to certain limitations discussed below).Income, credits and expenses attributable to the assets of the Trust and theTreasury Obligations are taken into account by Unitholders consistent withtheir method of accounting and without regard to the taxable year or accountingmethod employed by the Trust.

 

The Trust makes quarterly distributions to Unitholders of record oneach Quarterly Record Date. The terms of the Trust Agreement, as describedbelow, seek to assure to the extent practicable that taxable incomeattributable to such distributions will be reported by the Unitholder whoreceives such distribution, assuming that he is the owner of record on 

 

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theQuarterly Record Date. In certain circumstances, however, a Unitholder will notreceive the distribution attributable to such income. For example, if theTrustee establishes a reserve or borrows money to satisfy liabilities of theTrust, income associated with the cash used to establish that reserve or torepay that loan must be reported by the Unitholder, even though that cash isnot distributed to him. In addition, Unitholders must recognize certaininterest income attributable to the Treasury Obligations with respect to whichno current cash distributions will be made.

 

TheTrust allocates income, deductions and credits to Unitholders based on recordownership at Quarterly Record Dates. The IRS could require income anddeductions of the Trust to be determined and allocated daily or require somemethod of daily proration, which could result in an increase in theadministrative expenses of the Trust.

 

Undercurrent market conditions, it is anticipated that total distributable cash willexceed taxable income through 2004. After 2004, taxable income is anticipatedto exceed distributable cash, and the amount of such excess could besignificant. Such estimates are based on numerous assumptions as to theallocation of a Unitholder’s purchase price and the amount and treatment ofoperating costs, development costs, Trust administrative expenses, productionestimates and depletion. No assurance can be given that the estimates willprove to be correct, and the actual relationship between distributable cash andtaxable income could be materially different.

 

**Treatmentof Trust Units**

 

On theassumption that the Trust is a grantor trust for Federal income tax purposes,each Unitholder is treated as purchasing directly an interest in the NetProfits Interests. Purchasers of Depositary Units must allocate the portion of theirtotal purchase price allocated to the Trust Unit between the Royalty NPI andthe Term NPI in the proportion that the fair market value of each bears to thetotal fair market value of both. Information regarding purchase priceallocations is furnished to Unitholders by the Trustee.

 

**InterestIncome**

 

TheTerm NPI is treated as a “production payment” under Section 636(a) of theCode.  Thus, Unitholders are treated asmaking a mortgage loan on the Underlying Properties of the Term NPI to EasternAmerican in an amount equal to the amount of the purchase price of eachDepositary Unit allocated to the Term NPI. Because it is treated as a debt instrument for tax purposes, the TermNPI is subject to the original issue discount income (“OID”) rules of the Code whichgenerally require the periodic inclusion of the original issue discount inincome of the purchaser of a debt instrument. The Code also authorizes the IRS to prescribe regulations modifying thestatutory provisions where, by reason of contingent payments such as thoseprovided for by the Term NPI, the tax treatment provided under the Codeprovisions does not carry out the purposes of such provisions.

 

TheIRS has issued a series of proposed and final regulations dealing with debtinstruments which call for contingent payments. The initial set of proposed regulations dealing with this topic wereissued on April 8, 1986, and modified on February 26, 1991 (the “OldProposed Regulations”).  A second set ofproposed contingent payment regulations were issued on January 19, 1993,but were withdrawn prior to publication in the Federal Register.  On December 15, 1994, the IRS replacedthe Old Proposed Regulations by issuing a third set of proposed regulationsaddressing debt obligations that provide for contingent payments (the “NewProposed Regulations”).  The New 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.  Inthis regard, the New Proposed Regulations have been adopted in final form (the “FinalRegulations”), though effective only for debt instruments issued after August 12,1996. Thus, by their terms, the New Proposed Regulations and the FinalRegulations do not apply to the Term NPI. However, the Preamble to the Final Regulations provides that for debtinstruments issued prior to the effective date of the Final Regulations, ataxpayer may use any reasonable method to account for such debt instruments,including a method that would have been permitted under the proposedregulations when the debt instrument was issued.

 

TheTrustee understands that, in accordance with the foregoing, Eastern American,as obligor under the Term NPI, intends to continue to treat the Term NPI in themanner provided under the Old Proposed Regulations, which were proposed at thetime the Term NPI was transferred to the Trust and Trust Units wereissued.  Under this approach, eachpayment (at the time the amount of such payment becomes fixed) made to theTrust with respect to the Term NPI will be treated first as a payment ofinterest to the extent of interest deemed accrued under the OID rules and theexcess (if any) will be treated as a payment of principal.  The total amount treated as principal will belimited to a portion of the purchase price of each Depositary Unit allocated tothe Term NPI.  For purposes ofdetermining the amount of accrued interest, the Old Proposed Regulationsrequired the use of the Applicable Federal Rate based 

 

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onthe due date of the final payment due under the terms of the productionpayment, which for the Term NPI is May 15, 2013.

 

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

 

**RoyaltyIncome and Depletion**

 

Theincome from the Royalty NPI is royalty income subject to an allowance fordepletion. The depletion allowance must be computed separately by eachUnitholder for each oil or gas property (within the meaning of Code Section 614).The IRS presently takes the position that a net profits interest burdeningmultiple properties is one property for depletion purposes. Accordingly, thetax information reports that the Trust provides to Unitholders and the IRS havereported all production attributable to the Royalty NPI as productionattributable to a single property for depletion purposes.  Such reporting treatment is expected tocontinue until at least the IRS position on such treatment is changed.

 

Theallowance for depletion with respect to a property is determined annually andis the greater of cost depletion or, if allowable, percentage depletion.Percentage depletion is generally available to “independent producers”(generally persons who are not substantial refiners or retailers of oil or gasor their primary products) on the equivalent of 1,000 barrels of production perday. Percentage depletion is a statutory allowance equal to 15% of the grossincome from production from a property which is included in income by ataxpayer.

 

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

 

Incomputing cost depletion for each property for any year, the adjusted tax basisof that property at the end of that year is divided by the estimated totalunits (Mcf of gas) recoverable from that property to determine the per-unitallowance for such property. The per-unit allowance is then multiplied by thenumber of units produced and sold from that property during the year. Costdepletion for a property cannot exceed the adjusted tax basis of such property.While the Trust is treated as a grantor trust for Federal income tax purposes,each Unitholder computes cost depletion by using as his basis for the propertythe portion of his cost basis for his Depositary Units that is allocated firstto the NPI and second to the Royalty NPI. Information is provided by the Trustee to each Unitholder reflecting howthat basis should be allocated.

 

**Section 29Credit**

 

TheTrustee has been informed by Eastern American believes that most of theproduction attributable to the Royalty NPI is gas produced from Devonian shaleor a tight formation. Provided a number of requirements are met, taxpayers areentitled to the Section 29 Credit for gas produced from Devonian shale ora 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 after December 31,1979, and prior to January 1, 1993. Additionally, the Section 29Credit applies only to gas produced from a tight formation which, as of April 20,1977, was committed or dedicated to interstate commerce (as defined in Section 2(18)of the Natural Gas Policy Act, as in effect on November 5, 1990), or whichis produced from a well drilled after November 5, 1990. A Unitholder iseligible to claim the Section 29 Credit with respect to certain sales ofsuch gas attributable to the Royalty NPI. Under current law the Section 29 credit is no longer available forproduction after December 31, 2002.

 

Section 29Credits resulting from an investment in Depositary Units may only be used toreduce a taxpayer’s regular income tax liability and generally may not be usedto reduce a taxpayer’s liability for alternative minimum tax. Section 29Credits available to a taxpayer in any taxable year may not be carried back butmay be carried forward for use by that taxpayer in a subsequent tax year onlyin a limited fashion. See “Alternative Minimum Tax” below.

 

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The Section 29Credit is not available for production after December 31, 2002.  Congress in past years has considered,without enacting, legislation to extend energy tax credits such as the Section 29Credit beyond their expiration date or to create new similar credits.  The potential effect that enactment of anysuch possible legislation may have on Unitholders in the future is unknown.

 

On March 23,1999, the United States Tax Court of Appeals for the Tenth Circuit affirmed alower court decision in *True Oil Company v.*C.I.R.170 F.3d 1294.  The Court ruled that,in order to be eligible for credits under Section 29 of the InternalRevenue Code, each well from which gas is produced from Devonian shale or atight formation must receive a determination from the Federal Energy RegulatoryCommission (“FERC”) that the gas produced is, in fact, produced from Devonianshale 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 Internal Revenue Service challengethe amount of the Trust’s production qualifying for Section 29 Credits, aUnitholder might not be able to claim the benefit of Section 29 creditsfor production attributable to a well that did not receive a FERCdetermination.  If successful, such achallenge could affect the tax reporting for such credits for tax yearsexamined by the IRS and any subsequent tax years.  However, it should be noted that undercurrent law the Section 29 credit is no longer available for productionafter December 31, 2002.

 

**OtherIncome and Expenses**

 

Fromtime to time the Trust may generate interest income on funds held as a reserveor held until the next distribution date. Expenses of the Trust includeadministrative expenses of the Trustee. Under the Code, certain miscellaneousitemized deductions of an individual taxpayer are deductible only to the extentthat in the aggregate they exceed 2% of the taxpayer’s adjusted gross income.Certain administrative expenses attributable to the Trust Units may have to beaggregated with an individual Unitholder’s other miscellaneous itemizeddeductions to determine the excess over 2% of adjusted gross income. To datethe amount of such expenses has not been significant in relation to the Trust’sincome.

 

**AlternativeMinimum Tax**

 

The Code imposes a minimum tax (known as an “alternative minimum tax”or “AMT”) on each taxpayer to the extent that his “tentative minimum tax” inany taxable year exceeds his regular tax for that year. For purposes ofcomputing the AMT, the taxpayer’s taxable income is recomputed with various “adjustments”plus “items of tax preference”.

 

Ataxpayer is generally entitled to a credit against, orreduction in, his regular tax liability in a subsequent year in an amount equalto the AMT he pays for a prior taxable year. That credit can only be used toreduce his regular tax liability for that subsequent year to the extent hisregular tax liability for that subsequent year exceeds his tentative minimum taxliability for that subsequent year, however.

 

The Section 29Credit allowable to a taxpayer as a reduction of his tax liability for anyprior taxable year could not have exceeded the excess of his regular taxliability for such taxable year, as reduced by his foreign tax credits andcertain nonrefundable credits, over his tentative minimum tax liability forthat year. Any amount of Section 29 Credit disallowed for the prior taxyear solely because of this limitation will increase a taxpayer’s credit for theprior year’s AMT, as described above. There is no provision for the carrybackor carryforward of the Section 29 Credit in any other circumstances.Therefore, a Unitholder may not have received the full benefit of available Section 29Credits, depending on his particular AMT circumstances.  However it should be noted that under currentlaw the Section 29 credit is no longer available for production after December 31,2002.

 

Sincethe effect of the AMT varies depending upon each Unitholder’s personal tax andfinancial position, each Unitholder is advised to consult with his, her or itsown tax advisor concerning the effect of the AMT and Section 29 Creditsattributable to an investment in the Depositary Units.

 

**Non-PassiveActivity**

 

Theincome, credits and expenses of the Trust are not taken into account incomputing the passive activity losses and income under Code Section 469for a Unitholder who acquires and holds Depositary Units as an investment anddid not acquire them in the ordinary course of business.

 

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**UnrelatedBusiness Taxable Income**

 

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

 

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

 

Generally,a Unitholder will realize gain or loss on the sale or exchange of hisDepositary Units measured by the difference between the amountrealized on the sale or exchange and his adjusted basis for such DepositaryUnits. Gain or loss on the sale of Depositary Units by a Unitholder who is nota dealer with respect to such Depositary Units and who has a holding period forthe Depositary Units of more than one year will be treated as long-term capitalgain or loss except to the extent of the depletion recapture amount and anyaccrued market discount as explained below. A Unitholder’s initial basis in hisDepositary Units is equal to the amount paid for such Depositary Units. Suchbasis is increased by the amount of OID income recognized by the Unitholderattributable to the Treasury Obligations. Such basis is reduced by deductionsfor depletion claimed by the Unitholder (but not below zero). In addition, suchbasis is reduced by the amount of any payments attributable to the Term NPIwhich are treated as payments of principal under the OID rules.

 

ForFederal income tax purposes, the sale of a Depositary Unit is treated as a saleby the Unitholder of his interest in the Treasury Obligations and the assets ofthe Trust. Thus, upon the sale of Depositary Units, a Unitholder must treat asordinary income his depletion recapture amount, which is an amount equal to thelesser of (i) the gain on that sale attributable to disposition of the RoyaltyNPI or (ii) the sum of the prior depletion deductions taken with respect to theRoyalty NPI (but not in excess of the initial basis of such Depositary Unitsallocated to the Royalty NPI). It is possible that the IRS would take theposition that a portion of the sales proceeds is ordinary income to the extentof any accrued income at the time of sale allocable to the Depositary Unitssold, but which is not distributed to the selling Unitholder.

 

AUnitholder who allocates his purchase price (or is required to allocate hispurchase price) to the Treasury Obligations in an amount less than the sum of(a) his share of the initial issue price of the Treasury Obligations and (b)his share of OID income recognized by prior holders of the Treasury Obligations(any such difference represents “market discount”) will generally be requiredto recognize ordinary income to the extent of any accrued market discount uponsale 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 a DepositaryUnit bears to the number of days after the date the Unitholder acquired theDepositary Unit and up to and including the Liquidation Date.

 

**Withdrawalof Trust Units or Treasury Obligations**

 

AUnitholder will recognize no gain or loss upon the withdrawal of the TrustUnits or Treasury Obligations from the Depositary. A sale of the Trust Units orthe Treasury Obligations will result in the recognition 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 

 

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attributableto a sale of reserves by the Trust, depletion and Section 29 Creditsavailable to the Unitholders for subsequent periods is reduced.

 

**BackupWithholding**

 

Ingeneral, distributions of Trust income are not subject to “backup withholding”unless (i) the Unitholder is an individual or other noncorporate taxpayer and(ii) such Unitholder fails to comply with certain reporting procedures.

 

**TaxShelter Registration**

 

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

 

A Unitholderwho sells or otherwise transfers a Trust Unit must furnish to the transfereethe tax shelter registration number set forth above. The penalty for failure ofthe transferor of a Trust Unit to furnish such tax shelter registration numberto a transferee is $100 for each such failure. Unitholders must disclose thetax shelter registration number of the Trust on Form 8271 to be attached to thetax return on which any deduction, loss, credit or other benefit generated bythe Trust is claimed or income of the Trust is included. A Unitholder who failsto disclose the tax shelter registration number on his return, withoutreasonable cause for such failure, will be subject to a $250 penalty for eachsuch failure. (Any penalties discussed herein are not deductible for income taxpurposes.)

 

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

 

**STATE TAXCONSIDERATIONS**

 

Thefollowing is intended as a brief summary of certain information regarding stateincome taxes and other state tax matters affecting individual Unitholders.Unitholders are urged to consult their own legal and tax advisors with respectto these matters.

 

TheTrust owns the Net Profits Interests burdening the Underlying Propertieslocated in the states of Pennsylvania and West Virginia. Both of these stateshave income taxes applicable to individuals and may require the Trust towithhold taxes from distributions made to nonresident Unitholders. Withholding,if required, is at the rate of 4% of taxable income attributable to WestVirginia and 3.07% of taxable income attributable to Pennsylvania. A Unitholdermay be required to file state income tax returns and/or to pay taxes in thesestates and may be subject to penalties for failure to comply with suchrequirements. Generally, Unitholders may treat state income taxes that theTrust has withheld as having been paid by them to the state for which they werewithheld.  Unitholders may be able totreat any taxes that they have paid or that have been withheld and paid to WestVirginia or Pennsylvania as a deduction in computing Federal income tax, or asa credit or a deduction in computing another state’s income tax.

 

Unitholdersreceive information concerning the Depositary Units and the Trust Unitssufficient to identify the income from Depositary Units that is allocable toeach state. Holders of Depositary Units should consult their own tax advisorsto determine their income tax filing requirements with respect to their shareof income of the Trust allocable to states imposing a tax on such income.

 

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TheTrust Units and therefore also the Depositary Units may constitute realproperty or an interest in real property under the tax, inheritance, estate andprobate laws of either or both of Pennsylvania and West Virginia. If theDepositary Units are held to be real property or an interest in real propertyunder the laws of a state in which the Underlying Properties are located, theholders of Depositary Units may be subject to ad valorem or other property tax,devolution, probate and administration laws, and inheritance or estate andsimilar taxes, under the laws of such state.

 

**AvailableInformation**

 

TheTrust does not maintain an internet address or a website, and therefore doesnot make copies of its reports under the Exchange Act available in thatmanner.  The Trust’s filings under theExchange Act are available electronically from the website maintained by theSecurities and Exchange Commission at http://www.sec.gov.  The Trust will also provide electronic copiesof its recent filings free of charge upon request to the Trustee, and willprovide paper copies of its recent filings for its costs of reproduction uponrequest to the Trustee.

 

Item2.             *Properties.*

 

Referenceis made to Item 1 of this Form 10-K.

 

Item3.             *Legal Proceedings.*

 

None

 

Item4.             *Submission of Matters to a Vote of Unitholders.*

 

On November 30,2004, a special meeting of Unitholders was held to consider and act upon aproposal to elect JPMorgan Chase Bank, N.A. to serve as successor Trustee ofthe Trust effective upon the resignation of The Bank of New York and to amendthe terms of the Trust Agreement to increase the compensation payable to theTrustee, all as more fully set forth in the definitive proxy statement relatingto the special meeting.  The proposal wasapproved with 2,911,070 of the 3,171,188 Units represented at the meeting, inperson or by proxy, voting in favor of the proposal, 190,082 Units votingagainst the proposal, and 70,036 Units abstaining from voting on the proposal.

 

**PART II**

 

**Item 5****.****           *Market for the Registrant’s Common Equity, RelatedUnitholders Matters and Issuer Purchases of Equity Securities.***

 

TheDepositary Units are traded on the New York Stock Exchange under the tickersymbol “NGT”. The high and low prices and distributions paid during thequarters in the three-year period ended December 31, 2004 were as follows:

 
| ** **                         | ** ** | ** ** | ** ** | ** ** | ** ** | **Distributions** | ** ** |
|------------------------------------|------------|------------|------------|------------|------------|-------------------|------------|
| **Quarter**                        | ** ** | **High**   | ** ** | **Low**    | ** ** | **Paid**          | ** ** |
|                               |       |       |       |       |       |              |       |
| 2002:                              |       |       |       |       |       |              |       |
| First (to March 31, 2002)     |       | $          | 19.00      |       | $          | 17.22             |       | $ | 0.28 |   |
| Second (to June 30, 2002)     |       | $          | 18.40      |       | $          | 17.44             |       | $ | 0.33 |   |
| Third (to September 30, 2002) |       | $          | 19.00      |       | $          | 16.50             |       | $ | 0.34 |   |
| Fourth (to December 31, 2002) |       | $          | 19.22      |       | $          | 17.90             |       | $ | 0.37 |   |
|                               |       |       |       |       |       |              |       |
| 2003:                              |       |       |       |       |       |              |       |
| First (to March 31, 2003)     |       | $          | 19.58      |       | $          | 18.70             |       | $ | 0.38 |   |
| Second (to June 30, 2003)     |       | $          | 22.28      |       | $          | 18.87             |       | $ | 0.52 |   |
| Third (to September 30, 2003) |       | $          | 23.55      |       | $          | 20.83             |       | $ | 0.51 |   |
| Fourth (to December 31, 2003) |       | $          | 26.03      |       | $          | 22.10             |       | $ | 0.41 |   |
|                               |       |       |       |       |       |              |       |
| 2004:                              |       |       |       |       |       |              |       |
| First (to March 31, 2004)     |       | $          | 27.40      |       | $          | 22.95             |       | $ | 0.43 |   |
| Second (to June 30, 2004)     |       | $          | 23.80      |       | $          | 20.95             |       | $ | 0.49 |   |
| Third (to September 30, 2004) |       | $          | 25.65      |       | $          | 23.41             |       | $ | 0.48 |   |
| Fourth (to December 31, 2004) |       | $          | 27.00      |       | $          | 24.75             |       | $ | 0.62 |   |

 

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At March 29,2005, the 5,900,000 Depositary Units outstanding were held by approximately 279Unitholders of record.

 

Withrespect to the Treasury Obligations, the high and low closing prices per $1,000face amount for the period from October 1, 2004 to December 31, 2004were $707.90 and $687.30, respectively. The closing price on December 31, 2004 was $701.40 per $1,000 faceamount.

 

During the fourth quarter of 2004, there were nopurchases of Units made by or on behalf of the Trust or any “affiliatedpurchaser” as defined in Rule 10b-18 (a) (3) under the Exchange Act.

 

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

 
| ** **                     | ** ** | **December 31, 2004** | ** ** | **December 31, 2003** | ** ** | **December 31, 2002** | ** ** | **December 31, 2001** | ** ** | **December 31, 2000** | ** ** |
|--------------------------------|------------|-----------------------|------------|-----------------------|------------|-----------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **                     | ** ** | ** **            | ** ** | ** **            | ** ** | ** **            | ** ** | ** **            | ** ** | ** **            | ** ** |
| Royalty Income                 |       | $                     | 14,449,208 |                  | $          | 13,177,510            |       | $                     | 9,024,646  |                  | $          | 13,260,202 |   | $ | 11,569,718 |   |
| Distributable  Income          |       | $                     | 12,019,847 |                  | $          | 10,947,816            |       | $                     | 7,808,725  |                  | $          | 11,268,383 |   | $ | 9,776,735 |   |
| Distribution  Amount           |       | $                     | 11,919,847 |                  | $          | 10,732,816            |       | $                     | 7,808,725  |                  | $          | 11,268,383 |   | $ | 9,776,735 |   |
|                           |       |                  |       |                  |       |                  |       |                  |       |                  |       |
| Distributable  Income per unit |       | $                     | 2.04       |                  | $          | 1.86                  |       | $                     | 1.32       |                  | $          | 1.91 |   | $ | 1.66 |   |
| Distribution  Amount per unit  |       | $                     | 2.02       |                  | $          | 1.82                  |       | $                     | 1.32       |                  | $          | 1.91 |   | $ | 1.66 |   |
|                           |       |                  |       |                  |       |                  |       |                  |       |                  |       |
| Total assets at  year end      |       | $                     | 35,000,087 |                  | $          | 37,436,640            |       | $                     | 41,006,654 |                  | $          | 45,129,170 |   | $ | 50,964,669 |   |

 

**Item 7****.*****Management’sDiscussion and Analysis of Financial Condition and Results of Operations****.*

 

**General**

 

TheTrust does not conduct any operations or activities.  The Trust’s purpose is, in general, to holdthe Net Profits Interests, to distribute to Unitholders cash which the Trustreceives in respect of the Net Profits Interests and to perform certainadministrative functions in respect of the Net Profits Interests and theDepositary Units.  The Trust derivessubstantially all of its income and cash flows from the Net Profits Interests.

 

Underthe Gas Purchase Contract, Eastern Marketing purchases gas from the Trust at avariable price for any quarter equal to the Henry Hub Average Spot Price (asdefined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixedadjustment for Btu content.  The HenryHub Average 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 price determined for any month of suchquarter is equal to the average of (i) the final settlement price per MMBtu forHenry 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 price per MMBtu of Henry HubGas Futures Contracts determined as of the contract settlement date for suchmonth, as reported in *The Wall Street Journal*,for such contracts which expire in each of the six months following suchmonth.  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.

 

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Accordingly, the price payable to the Trust for production may varybased on fluctuations in natural gas futures prices during the relevantcalculation period.  The price payable tothe Trust will have a direct impact, positively or negatively, on the quarterlydistributions payable by the Trust to the Unitholders.

 

During2002, Eastern American was asked to sell 3 wells in which the Trust owned a NetProfits Interest (the Western Pocahontas #7, #8 and #10 wells).  The party seeking to purchase the wells ownedthe right to mine for coal on such properties (the “Coal Lessee”).  The Coal Lessee stated that the wells wouldmaterially interfere with the Coal Lessee’s proposed mining operations.

 

EasternAmerican reviewed the Trust Agreement and production from these wells, anddetermined that the Net Profits Interest associated with the Western Pocahontas# 7 well accounted for more than 0.25% of the total production from theUnderlying Properties for the prior twelve (12) month period.  Eastern American advised the Coal Lessee thatit could not sell this well.

 

Subsequently,the Coal Lessee asserted that the coal estate in the relevant Underlying Propertieswas the dominate estate and that under the relevant oil and gas leases andapplicable case law, the Coal Lessee could cause the Trust and Eastern Americanto plug and abandon the well.  EasternAmerican and the Trust did not necessarily agree with the Coal Lessee position,however, and in an effort to avoid litigation, the Trust and Eastern Americanentered into a Settlement Agreement and Release of All Claims with the CoalLessee pursuant to which Eastern agreed to sell the Western Pocahontas # 7 wellfor the amount of $426,187.  The Trust’sshare of the proceeds of $303,438 was included in Distributable Income to theTrust during the year ended December 31, 2002.  The Coal Lessee purchased the two additionalwells, the Western Pocahontas # 8 and #10 for the amount of $209,561.  The Trust’s share of the proceeds of $188,605was also included in the Distributable Income of the Trust during the yearended December 31, 2002.

 

During2003, a Coal Lessee contacted Eastern American and inquired as to whether itwould sell the U.S. Steel Well # 26, which is a well in which the Trust owns aNet Profits Interests.  The Coal Lesseestated that the well would materially interfere with the Coal Lessee’s proposedmining operations.  Eastern Americanreviewed the Trust Agreement and production from this well to determine if itcould cause the Trust to sell its Net Profits Interest in the well.  Upon review, it was discovered that the NetProfits Interests associated with the U.S. Steel #26 well accounted for lessthan 0.25% of the total production from the Underlying Properties for the priortwelve (12) month period.  EasternAmerican advised the Coal Lessee that it could sell this well.  Eastern American received $11,437 for thesale of the U.S Steel Well #26.  TheTrust’s share of the proceeds of $10,293 was included in the DistributableIncome of the Trust during the year ended December 31, 2003.

 

During2004, an oil and gas company contacted Eastern American and inquired as towhether it would sell certain assets situated in Centre County, Pennsylvaniaincluding the Horne #1, Horne #2 and Horne #15 wells (the Horne UnderlyingProperties), which are wells in which the Trust owns a Net ProfitsInterests.  Eastern American reviewed theTrust Agreement and certified to the Trustee that:  (i) the gross purchase price to be receivedby Eastern American for the sale of the Horne Underlying Properties in a singletransaction or a series of related transactions was less than $500,000; (ii)the Assignee of the Horne Underlying Properties was not an Affiliate of EasternAmerican; (iii) the aggregate sale proceeds of $80,205 to be received by theTrust from Eastern American (the Trust’s Horne Sale Proceeds) represented thefair value to the Trust for Net Profits Interests to be released by the Trusteein connection with Eastern American’s sale of the Horne Underlying Properties;and (iv) the Trust’s Horne Sale Proceeds plus the aggregate sale proceedsreceived by the Trust pursuant to Section 3.02(b)(ii) of the TrustAgreement with respect to all other Net Profits Interests previously releasedby the Trustee pursuant to Section 3.02(b) during the most recentlycompleted twelve calendar months did not exceed $500,000.  Eastern American advised the oil and gascompany that it could sell these wells. The Trust’s share of the proceeds of $80,205 was included in theDistributable Income of the Trust during the year ended December 31, 2004.

 

Also,during 2004, a landowner contacted Eastern American to inquire about the saleof certain wells located on the landowner’s property, including the Wurst #2well, which is a well in which the Trust owns a Net Profits Interest.  Eastern certified to the Trust that, (i) theAssignee of the Wurst #2 was not an Affiliate of Eastern and, (ii) the aggregatesale proceeds to be received from all other sales of wells in which the Trustowns a Net Profits Interest and previously released by the Trust during thepreceeding twelve (12) calendar months did not exceed $500,000.  The Wurst #2 well was found to be uneconomicto operate and was subject to plugging and abandonment by Eastern American ifnot 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.

 

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Overthe remaining life of the Trust, additional wells may need to be disposed offor similar or other reasons.

 

The Trust is responsible for paying the Trustee’s fees and all legal,accounting, engineering and stock exchange fees, printing costs and otheradministrative expenses incurred by or at the direction of the Trustee.  The total of all Trustee fees and Trustadministrative expenses for 2004 was $695,805, including the Trustee’s fee of$45,000.  In addition to such expenses,in 2004, the Trust paid Eastern American an overhead reimbursement of$306,592.  The overhead reimbursementincreases by 3.5% per year and is payable quarterly.

 

On December 8,2004 the Trust announced approval by the Trust Unitholders of a proposal toelect JPMorgan Chase to serve as successor trustee of the Trust upon theeffective date of the resignation of The Bank of New York as trustee of anddepositary for the Trust and to amend the Trust Agreement to change thecompensation of the Trustee.  Theresignation of The Bank of New York took effect on January 1, 2005.  As successor trustee, JPMorgan Chase willreceive annual compensation of $108,000, plus fees and expenses.

 

The costs the Trust incurs in the future will fluctuate dependingprimarily on the expenses the Trust incurs for professional services,particularly legal, accounting and engineering services.

 

**CriticalAccounting Policies**

** **

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

 

*Basis ofAccounting:*

 

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.

 

*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 a writedown is necessary to its investmentin the Net Profits Interests in gas properties to the extent that totalcapitalized costs, less accumulated amortization, exceed undiscounted futurenet revenues attributable to proved gas reserves of the UnderlyingProperties.  The Trust will then providea writedown to the extent that the net capitalized costs exceed the discountedfuture net revenues attributable to proved gas reserves of the UnderlyingProperties.  Any such writedown would notreduce distributable income, although it would reduce 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 perreserve unit.  Such amortization does notreduce distributable income, rather it is charged directly to TrustCorpus.  Revisions to estimated futureunits-of-production are treated on a prospective basis beginning on the datesignificant revisions are known.

 

TheNet Profits Interest impairment test and the determination of amortizationrates are dependent on estimates of proved gas reserves attributable to theTrust.  Numerous uncertainties areinherent in estimating reserve volumes and values, including economic andoperating conditions, and such estimates are subjectto change as additional information becomes available.

 

*IncomeTaxes:*

 

**Tax counsel to the Trust advisedthe Trust at the time of formation that, under then current tax laws, the Trustwould be classified as a grantor trust for federal and state income taxpurposes and, therefore, would not be subject to taxation at the Trustlevel.  The Trust continues to be taxexempt. Accordingly, no provision for federal or state income taxes has beenmade.  However, the opinion of taxcounsel is not binding on taxing authorities.**

 

21

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**Liquidityand Capital Resources**

** **

TheTrust has no source of liquidity or capital resources other than thedistributions received from the Net Profits Interests.

 

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

 

The Trust did nothave any contractual obligations as of December 31, 2004.  At December 31, 2004, the Trust hadaccounts payable of $220,596 and distributions payable of $3,639,983.

 

#### **Resultsof Operations**

#### ** **

##### 2004 Compared with 2003

 

The Trust’s distributableincome was $12,019,847 for the twelve months ended December 31, 2004 ascompared to $10,947,816 for the twelve months ended December 31,2003.  This increase was due to anincrease in Royalty Income for the twelve months ended December 31, 2004($14,449,208) as compared to the twelve months ended December 31, 2003($13,177,510).  The increase in RoyaltyIncome was due to an increase in the average price payable to the Trust underthe Gas Purchase Contract as discussed below ($6.989 per Mcf for the twelvemonths ended December 31, 2004; $6.086 per Mcf for the twelve months endedDecember 31, 2003).  This increasewas offset by a decrease in production of gas attributable to the Net ProfitsInterests for the twelve months ended December 31, 2004 (2,068 Mmcf) ascompared to the twelve months ended December 31, 2003 (2,161 Mmcf).  The decline in production is primarilyattributable to natural production declines and the sale of wells.  Taxes on production and property were$989,430 for the twelve months ended December 31, 2004 as compared to$897,881 for the twelve months ended December 31, 2003.  The increase in taxes is due directly to theincrease in Royalty Income as discussed above. Trust general and administrativeexpenses were $1,002,397 for the twelve months ended December 31, 2004 ascompared to $833,027 for the twelve months ended December 31, 2003.  The increase in general and administrativeexpenses was due primarily to an increase in legal fees of $64,234 and $51,406in direct expenses related to the resignation of the former trustee and theappointment of a successor trustee.  Thedistributable income includes Cash Proceeds on Sale of Net Profits Interests of$80,205 for the period ended December 31, 2004, while $10,293 wasrecognized in the corresponding prior twelve months.

 

During the twelve monthsended December 31, 2004, the Trustee added an additional $100,000 to thecash reserve balance which was established during the twelve months ended December 31,2003 in the amount of $215,000.  Thisreserve was established to facilitate the payment of vendor invoices on atimely basis.  The establishment andsubsequent increase of this reserve reduced the Distribution Amount by $100,000or $0.0169 per unit for the twelve months ended December 31, 2004 and by$215,000 or $0.0365 per unit for the twelve months ended December 31,2003. Amortization of Nets Profits Interests in Gas Properties was $3,818,158for the twelve months ended December 31, 2004 as compared to $4,053,133for the twelve months ended December 31, 2003.  This decrease was primarily due to thedecrease in production volumes.

 

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

 

##### 2003 Compared with 2002

 

The Trust’s distributableincome was $10,947,816 for the twelve months ended December 31, 2003 ascompared to $7,808,725 for the twelve months ended December 31, 2002.  This increase was due to an increase inRoyalty Income for the twelve months ended December 31, 2003 ($13,177,510)as compared to the twelve months ended December 31, 2002($9,024,646).  The increase in RoyaltyIncome was due to an increase in the average price payable to the Trust underthe Gas Purchase Contract as discussed below ($6.086 per Mcf for the twelvemonths ended December 31, 2003; 

 

22

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$3.829 per Mcf for the twelve months ended December 31,2002).  This increase was offset by adecrease in production of gas attributable to the Net Profits Interests for thetwelve months ended December 31, 2003 (2,161 Mmcf) as compared to thetwelve months ended December 31, 2002 (2,357 Mmcf).  The decline in production is primarilyattributable to natural production declines and the sale of wells.  Taxes on production and property were$897,881 for the twelve months ended December 31, 2003 as compared to$613,115 for the twelve months ended December 31, 2002.  The increase in taxes is due directly to theincrease in Royalty Income as discussed above. Trust general and administrativeexpenses were $833,027 for the twelve months ended December 31, 2003 ascompared to $594,921 for the twelve months ended December 31, 2002.  The increase in general and administrativeexpenses was due primarily to an increase in legal fees of $145,269 and an$81,042 increase due to the timing of payments for tax and audit servicesperformed as well as an increase in fees for such services.  The distributable income includes CashProceeds on Sale of Net Profits Interests of $10,293 for the period ended December 31,2003, while $492,043 was recognized in the corresponding prior twelve months.

 

During the twelve monthsended December 31, 2003, the Trustee established a cash reserve in theamount of $215,000 to facilitate the payment of vendor invoices on a timelybasis. No such reserve existed in the prior twelve months ended December 31,2002.  Establishing this reserve reduceddistributions payable by $215,000 or $0.0365 per unit for the twelve monthsended December 31, 2003. Amortization of Nets Profits Interests in GasProperties was $4,053,133 for the twelve months ended December 31, 2003 ascompared to $4,474,182 for the twelve months ended December 31, 2002.  This decrease was primarily due to thedecrease in production volumes.

 

Theaverage price payable to the Trust for gas production attributable to the NetProfits Interests was $6.086 per Mcf for the twelve months ended December 31,2003 and $3.829 per Mcf for the twelve months ended December 31,2002.  The price per Mcf was higher forthe twelve months ended December 31, 2003 than for the correspondingtwelve month period ended December 31, 2002 due to an increase in theaverage spot market price for gas delivered at the Henry Hub near Henry,Louisiana ($5.233 per Dth for the twelve months ended December 31, 2003;$3.181 per Dth for the twelve months ended December 31, 2002).

 

**Off-BalanceSheet Arrangements**

** **

The Trust does not have any off-balance sheetarrangements that have or are reasonably likely to have a current or futureeffect on the Trust’s financial condition, changes in financial condition,revenue or expenses, results of operations, liquidity, capital expenditures orcapital resources that is material to investors.

 

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

 

TheTrust does not engage in any operations, and does not utilize market risksensitive instruments, either for trading purposes or for other than tradingpurposes.  As described in detailelsewhere herein, the Depositary Units consist of beneficial ownership of oneunit of beneficial interest in the Trust and a $20 face amount beneficialownership interest in a $1,000 face amount zero coupon Treasury Obligationmaturing on May 15, 2013.  High and lowprice information for the Treasury Obligations is included under Item 5.  As described in detail elsewhere herein, gasproduction attributable to the Net Profits Interest is sold to a wholly ownedsubsidiary of Eastern American pursuant to the Gas Purchase Contract described herein.

 

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

 
|                                                                                              | **Page in this Form 10-K** |
|---------------------------------------------------------------------------------------------------|----------------------------|
|                                                                                              |                       |
| Financial Statements                                                                              |                       |
| Report  of Independent Registered Public Accounting Firm                                          | F-2                        |
| Statements  of Assets, Liabilities and Trust Corpus as of December 31, 2004 and 2003         | F-3                        |
| Statements of  Distributable Income for the years ended December 31, 2004, 2003 and  2002    | F-4                        |
| Statements of  Changes in Trust Corpus for the years ended December 31, 2004, 2003 and  2002 | F-5                        |
| Notes to Financial  Statements                                                                    | F-6                        |

 

**Item 9****.*****           Changes in and Disagreements with Accountants on Accounting andFinancial Disclosure.***

 

None.

 

23

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** **

**Item 9A**.  Controls and Procedures

** **

**Evaluation of Disclosure Controls andProcedures**

 

TheTrustee maintains disclosure controls and procedures designed to ensure thatinformation required to be disclosed by the Trust in the reports that it filesor submits under the Exchange Act of 1934, as amended, is recorded, processed,summarized and reported within the time periods specified in the SEC’s rulesand regulations.  Disclosure controls andprocedures include controls and procedures designed to provide reasonableassurance that information required to be disclosed by the Trust is accumulatedand communicated by several parties, including without limitation, the workinginterest owner, Eastern American Energy Corporation (“Eastern American”), andthe independent reserve engineer to JPMorgan Chase Bank, N.A., as Trustee ofthe Trust, and its employees who participate in the preparation of the Trust’speriodic reports as appropriate to allow timely decisions regarding requireddisclosure.  In addition, the Trustee isrequired by the Trust Agreement to engage and has engaged an independentregistered public accounting firm to review the quarterly financial statementsof the Trust and audit the annual financial statements of the Trust, whichincludes financial data provided by Eastern American.

 

As of December 31,2004, the former Trustee carried out an evaluation of the former Trustee’sdisclosure controls and procedures, as defined under Rule 13a-15(e) and15d-15(e) under the Securities Exchange Act. Patrick Tadie, a Vice President of The Bank of New York, has concludedthat the disclosure controls and procedures are effective at the reasonableassurance level, while noting certain limitations on disclosure controls andprocedures as set forth below.

 

Due tothe contractual arrangements of (i) the Trust Agreement and (ii) the rights ofthe Trustee under the Conveyances regarding information furnished by EasternAmerican, there are certain potential weaknesses that may limit theeffectiveness of disclosure controls and procedures established by the Trusteeor its employees and their ability to verify the accuracy of certain financialinformation.  The contractual limitationscreating potential weaknesses in disclosure controls and procedures may bedeemed to include:

 

•                  Eastern American and its consolidatedsubsidiaries manage (i) historical operating data, including productionvolumes, marketing of products, operating and capital expenditures,environmental and other liabilities, the effects of regulatory changes and thenumber of producing wells and acreage, (ii) plans for future operating andcapital expenditures and (iii) geological data relating to reserves.  While the Trustee requests materialinformation for use in periodic reports as part of its disclosure controls andprocedures, the Trustee does not manage this information, and relies to theextent considered reasonable on Eastern American to provide accurate and timelyinformation when requested for use in the Trust’s reports.

•                  Under the terms of the Trust Agreement,the Trustee is entitled to, and in fact does, rely upon in good faith, theindependent reserve engineer, as an expert with respect to the annual reservereport, which includes projected production, operating expenses and capitalexpenses.  Other than reviewing thefinancial and other information provided to the Trust by Eastern American on aquarterly basis, the Trustee makes no independent or direct verification ofthis financial or other information. While the Trustee has no reason to believeits reliance upon this expert is unreasonable, this reliance on an expert andrestricted access to information may be viewed as a weakness.

 

TheTrustee does not intend to expand its responsibilities beyond those permittedor required by the Trust Agreement and those required under applicable law.

 

**Changes inInternal Controls**

 

Asdescribed elsewhere herein, The Bank of New York served as Trustee through December 31,2004, and effective January 1, 2005, JPMorgan Chase Bank, N.A. wasappointed successor Trustee.  Theevaluation described above of the disclosure controls and procedures as of December 31,2004 was conducted by an officer of The Bank of New York.  To the knowledge of the Trustee, during thethree-month period ended December 31, 2004, there has not been any changesin the Company’s internal control over financial reporting, as such term isdefined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act that hasmaterially affected, or is reasonably likely to materially affect, the Company’sinternal control over financial reporting. The Trustee notes for purposes of clarification that it has no authorityover, and makes no statement concerning, the internal controls of EasternAmerican.

 

24

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**Status of Management’s Report on Internal Controlover Financial Reporting**

 

TheSarbanes-Oxley Act of 2002  (the “Act”)imposed many requirements regarding corporate governance and financialreporting.  One requirement under section 404of the Act, beginning with this annual report, is for management to report onthe Trust’s internal control over financial reporting as of December 31,2004 and for the Trust’s independent registered public accounting firm toattest to the report.  In November 2004the SEC issued an exemptive order providing a 45-day extension for the filingof these reports, and the Trust intends to include the reports in an amendedForm 10-K expected to be filed in April 2005.  Although management has not identified anymaterial weakness in the internal control over financial reporting based on thetesting performed to date, material weaknesses or deficiences may still beidentified.

 

**Limitations on the Effectiveness ofControls**

 

TheTrustee does not expect that the Trust’s disclosure controls and procedures orthe Trust’s internal control over financial reporting will prevent all errorsand all fraud.  A registrant’s internalcontrol over financial reporting is a process designed to provide reasonableassurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generallyaccepted accounting principles. A registrant’s internal control over financialreporting includes those policies and procedures that (i) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the registrant; (ii)provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generallyaccepted accounting principles, and that receipts and expenditures of theregistrant are being made only in accordance with authorizations of managementand directors of the registrant; and (iii) provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use, ordisposition of the registrant s assets that could have a material effect on thefinancial statements.

 

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

 

Further,the design of disclosure controls and procedures and internal control overfinancial reporting must reflect the fact that there are resource constraints,and the benefits of controls must be considered relative to their costs.Because of the inherent limitations in all control systems, no evaluation ofcontrols can provide absolute assurance that all control issues and instancesof fraud, if any, have been detected.

 

**Item 9B****.****                           *Other Information.***

 

Duringthe fourth quarter of 2004, the Trust issued a press release dated November 9,2004, a copy of which is filed as Exhibit 99.1 hereto, which was inadvertentlynot filed under Form 8-K.

 

**PART III**

** **

**Item 10.****                             *Directors and Executive Officers of the Registrant.***

 

The Trust has no directors 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 toand does not hold annual meetings of the Unitholders.

 

The Trust also does not have an audit committee or body serving asimilar function, and does not have an “audit committee financial expert”.  The Trust has not adopted a code of ethics,as the Trust has no directors, officers, or employees.  The Trust has not adopted a process by whichUnitholders may communicate with Board Members, as the Trust has no boardmembers or persons fulfilling a similar function.  Unitholders may contact the Trustee at thefollowing address:  JPMorgan Chase Bank,N.A., Trustee  Institutional TrustServices, 700 Lavaca, Austin, Texas 78701.

 

25

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

 

The Trust has no officers or directors, and is administered by theTrustee.  For the years ended December 31,2004, 2003 and 2002, The Bank of New York as Trustee received $45,000 annually,as Trustee fees and $650,805, $491,803 and $263,713, respectively, asreimbursement of legal, accounting, and other professional expenses for suchservices.  Effective January 1,2005, the annual Trustee fee increased to $108,000.

 

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

 

(a)                                                       SecurityOwnership of Certain Beneficial Owners.

 

Based on filings with the Securities and ExchangeCommission, the Trust is not aware of any person owning beneficially more thanfive percent of the Units as of March 1, 2005.

 

(b)                                                      SecurityOwnership of Management.

 

Not applicable.

 

(c)                                                       Changesin Control.

 

The Trust knows of no arrangements, including thepledge of securities of the Trust, the operation of which may at a subsequentdate result in a change in control of the Trust.

 

(d)                                                      Securitiesauthorized for issuance under equity compensation plans.

 

TheTrust has no equity compensation plans.

 

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

 

None.

 

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

 

**Audit Fees**

 

Thefees, including expenses, PricewaterhouseCoopers LLP billed the Trust for eachof the last two fiscal years for professional services rendered in connectionwith the audits of the Trust’s annual financial statements and review of theTrust quarterly interim financial statements were $69,575 in 2004 and $71,962in 2003.

 

**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**

 

Thefees, including expenses, PricewaterhouseCoopers LLP billed the Trust for eachof the last two fiscal years for compliance, tax advice, or planning were$67,417 in 2004 and $126,681 in 2003.

 

**All Other Fees**

 

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

 

**Pre-Approval Policies**

 

TheTrust does not have an audit committee or body performing a similarfunction.  Pre-approval of all servicesperformed by PricewaterhouseCoopers LLP and approval of the related fees isgranted by the Trustee.

 

26

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PART IV

 

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

 
| Reports                                                                                                     | **Page in  this Form 10-K** |
|-------------------------------------------------------------------------------------------------------------|-----------------------------|
| Reserve  Report of Ryder Scott Company, Independent Petroleum Engineers                                     | A-1 - A-5                   |
|                                                                                                        |                        |
| 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                                                    | F-2                         |
| Statements  of Assets, Liabilities and Trust Corpus as of December 31, 2004 and 2003                   | F-3                         |
| Statements of  Distributable Income for the years ended December 31, 2004, 2003 and  2002              | F-4                         |
| Statements of  Changes in Trust Corpus for the years ended December 31, 2004, 2003 and  2002           | F-5                         |
| Notes to Financial  Statements                                                                              | F-6 - F-14                  |

 

Schedules

All schedules have been omitted because they are notrequired, not applicable or the information required has been includedelsewhere herein.

 

Exhibits

Except asotherwise indicated below, all exhibits, except Exhibit 31 and Exhibit 32 and99.1, are incorporated herein by reference to the indicated exhibits to filingspreviously made by the registrant with the Securities and ExchangeCommission.   All references are to theregistrant’s Registration Statement on Form S-1, Registration No. 33-56336,except for Exhibit 3.1, which is incorporated by reference to the Registrant’sAnnual Report 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 |
| 99.1                |       |       | Press Release issued November 9, 2004 |

 

27

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**SIGNATURES**

 

**Pursuantto the requirements of Section 13 or 15(d) of the Securities Exchange Actof 1934, the registrant has duly caused this report to be signed on its behalfby the undersigned, thereunto duly authorized on this 28th day of March, 2005.**

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

 

TheRegistrant, Eastern American Natural Gas Trust, has no principal executiveofficer, principal financial officer, controller or principal accountingofficer, board of directors or persons performing similar functions.  Accordingly, no additional signatures areavailable and none have been provided.

 

28

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[Ryder Scott Company,Independent Petroleum Engineers Letterhead]

 

February 10, 2005

 

Eastern American Natural Gas Trust

The Bank of New York

2 North LaSalle Street, Suite 1020

Chicago, Illinois 60602

 

Gentlemen:

 

Pursuant to your request, we present below estimatesof the net proved reserves attributable to the interests of the EasternAmerican Natural Gas Trust (Trust) as of December 31, 2004.  The Trust is a grantor trust formed to holdinterests in certain domestic oil and gas properties owned by Eastern AmericanEnergy Corporation (EAEC), a wholly owned subsidiary of Energy Corporation ofAmerica (ECA).  The interests conveyed tothe Trust consist of a net profits interest derived from working and royaltyinterests in numerous properties.  TheNet Profits Interest consists of (1) a life-of-properties interest (“RoyaltyNPI”) and (2) a term interest (“Term NPI”). The properties included in the Trust are located in the states ofPennsylvania and West Virginia.

 

The estimated reserve quantities and future incomequantities presented in this report are related to a large extent tohydrocarbon prices.  Hydrocarbon pricesin effect at December 31, 2004 were used in the preparation of this reportas required by Securities and Exchange Commission (SEC) and FinancialAccounting Standards Bulletin No. 69 (FASB 69) guidelines; however, actualfuture prices may vary significantly from December 31, 2004 prices forreasons discussed in more detail in other sections of this report.  Therefore, quantities of reserves actuallyrecovered and quantities of income actually received may differ significantlyfrom the estimated quantities presented in this report.

 
| ** **           | ** ** | **As of December 31, 2004** | ** ** | ** **       | ** ** |
|----------------------|------------|----------------------------------|------------|------------------|------------|
| ** **           | ** ** | ** **                       | ** ** | **Estimated**    | ** ** | **Present** | ** ** |
| ** **           | ** ** | ** **                       | ** ** | **Future Net**   | ** ** | **Value** | ** ** |
| ** **           | ** ** | **Gas**                          | ** ** | **Cash Inflows** | ** ** | **At 10%** | ** ** |
| ** **           | ** ** | **(MMCF)**                       | ** ** | **(M$)**         | ** ** | **(M$)** | ** ** |
| Proved Net Developed |       |                             |       |             |       |   |   |
|                 |       |                             |       |             |       |   |   |
| Royalty NPI          |       | 11,456                           |       | 91,886           |       | 38,406 |   |
| Term NPI             |       | 6,702                            |       | 53,758           |       | 37,790 |   |
| Total                |       | 18,158                           |       | 145,644          |       | 76,196 |   |

 

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, 2005 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 ProfitsInterests have been proportionately reduced to reflect the future estimatedcosts and expenses deducted in the calculation of Net Proceeds with respect tothe Net Profits Interests.  Accordingly,the reserves presented for the Net Profits Interest reflect quantities of gasthat are free of future costs or expenses based on the price and costassumptions utilized in this report.  Theallocation of proved reserves of the Net Profits Interest between the Trust andEAEC will vary in the future as relative estimates of future gross revenues andfuture net incomes vary.  Furthermore,EAEC requested 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 

 

A-1

----

 

from the properties burdened by the “Term NPI” untilthe earlier of May 15, 2013 or until such time as 41,683 MMCF of gas has beenproduced.  For purposes of this report,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:

 

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 the reservoir.  Proved reserves are estimates of hydrocarbonsto be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional databecomes available. Proved natural gas reserves consist of non-associated,associated and dissolved gas.  Anappropriate reduction in gas reserves has been made for the expected removal ofnatural gas liquids, for lease and plant fuel, and for the exclusion ofnon-hydrocarbon gases if they occur in significant 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) “developed reserves” which are those provedreserves reasonably expected to be recovered through existing wells with existingequipment and operating methods, including (a) “developed producing reserves”which are those proved developed reserves reasonably expected to be producedfrom existing completion intervals now open for production in existing wells,and (b) “developed non-producing reserves” which are those proved developedreserves which exist behind the casing of existing wells which are reasonablyexpected to be produced through these wells in the predictable future where thecost of making such hydrocarbons available for production should be relativelysmall compared to the cost of a new well; and

 

(ii) “undeveloped reserves” which are those provedreserves reasonably expected to be recovered from new wells on undrilledacreage, from existing wells where a relatively large expenditure is requiredand from acreage for which an application of fluid injection or other improvedrecovery technique is contemplated where the technique has been provedeffective by actual tests in the area in the same reservoir.  Reserves from undrilled acreage are limitedto those drilling units offsetting productive units that are reasonably certainof production when drilled.  Provedreserves for other undrilled units are included only where it can bedemonstrated with reasonable certainty that there is continuity of productionfrom the existing productive formation.

 

A-2

----

 

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 31,2004 from this report are presented in the following table:

 
| ** **                                      | ** ** | **As of December 31, 2004** | ** ** |
|-------------------------------------------------|------------|----------------------------------|------------|
| ** **                                      | ** ** | **Royalty**                      | ** ** | **Term** | ** ** | ** ** | ** ** |
| ** **                                      | ** ** | **NPI**                          | ** ** | **NPI** | ** ** | **Totals** | ** ** |
| Total Proved                                    |       |                             |       |   |   |   |   |
| Future Cash Inflows  (M$)                       |       | 91,886                           |       | 53,758 |   | 145,644 |   |
| Future Costs                                    |       |                             |       |   |   |   |   |
| Production (M$)                                 |       | 0                                |       | 0 |   | 0 |   |
| Development (M$)                                |       | 0                                |       | 0 |   | 0 |   |
| Total Costs (M$)                                |       | 0                                |       | 0 |   | 0 |   |
|                                            |       |                             |       |   |   |   |   |
| Future Net Cash Inflows  Before Income Tax (M$) |       | 91,886                           |       | 53,758 |   | 145,644 |   |
|                                            |       |                             |       |   |   |   |   |
| Present Value at 10%  Before Income Tax (M$)    |       | 38,406                           |       | 37,790 |   | 76,196 |   |

 
| ** **                      | ** ** | **As of December 31, 2004** | ** ** |
|---------------------------------|------------|----------------------------------|------------|
| ** **                      | ** ** | **Royalty**                      | ** ** | **Term** | ** ** | ** ** | ** ** |
| ** **                      | ** ** | **NPI**                          | ** ** | **NPI** | ** ** | **Totals** | ** ** |
| Proved Net Developed Reserves   |       |                             |       |   |   |   |   |
| Gas (MMCF)                      |       | 11,456                           |       | 6,702 |   | 18,158 |   |
|                            |       |                             |       |   |   |   |   |
| Proved Net Undeveloped Reserves |       |                             |       |   |   |   |   |
| Gas (MMCF)                      |       | 0                                |       | 0 |   | 0 |   |
|                            |       |                             |       |   |   |   |   |
| Total Proved Net Reserves       |       |                             |       |   |   |   |   |
| Gas (MMCF)                      |       | 11,456                           |       | 6,702 |   | 18,158 |   |

 

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 31,2004 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 January 1of each year during the primary term beginning in 1994. The second component isthe “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 

 

A-3

----

 

final settlement prices per MMBtu for Henry Hub GasFutures Contracts (as defined), as reported in the Wall Street Journal,for such contracts which expired in each of the five months prior to each monthof such quarter, (ii) the final settlement price per MMBtu for Henry Hub GasFutures Contracts, as reported 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 for such month, as reportedin the Wall Street Journal, for such contracts which expire in each ofthe 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.  The weighted average price isdetermined by giving the “Fixed” price a 66 2/3 percent weighting and thevariable 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, 2004 as $8.021 per Mcf, utilizing $6.992as the Henry Hub Average Spot Price computed in accordance with the gascontract.

 

Operating costs for the leases and wells in thisreport were supplied by EAEC and include only costs defined as applicable underterms of the Trust.  The currentoperating costs 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 liabilitieswhich may exist nor were any costs included for potential liability to restoreand clean up damages, in any, caused by past operating practices.  EAEC informed us that it has furnished us allof the accounts, records, geological and engineering data and reports and otherdata as were required for our investigation. The ownership interests, terms ofthe Trust, prices, taxes, and other factual data furnished to us in connectionwith our investigation were accepted as represented.  The estimates presented in this report arebased on data available through July, 2004.

 

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 theUnderlying Properties:

 

A-4

----

 

Estimated Net ReserveData

Certain CombinedLeasehold Interests of

Eastern America EnergyCorporation

And The Trust

As of December 31,2004

SEC Parameters

 
| ** **             | ** ** | **Proved**    | ** ** | **Total**       | ** ** |
|------------------------|------------|---------------|------------|-----------------|------------|
| ** **             | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Proved** | ** ** |
| Net Remaining Reserves |       |          |       |            |       |   |   |
|                   |       |          |       |            |       |   |   |
| Gas-MMCF               |       | 36,328        |       | 0               |       | 36,628 |   |

 

The estimated future net income associated with theforegoing volumes and the 10 percent discounted estimated future net income was$244,990,453 and $99,361,100, 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.      |
|   |                           |
|   |                           |
|   | Larry T. Nelms P. E.           |
|   | Managing Senior Vice President |
|   |
| LTN:ph |

 

A-5

----

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EASTERN AMERICAN NATURALGAS TRUST

 

FINANCIAL STATEMENTS

 

as of December 31,2004 and 2003

and for the years ended

December 31, 2004,2003 and 2002

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

----

 

REPORT OF INDEPENDENT REGISTERED PUBLICACCOUNTING FIRM

 

To the Unitholders andJPMorgan Chase Bank, N.A.,

As Trustee for EasternAmerican Natural Gas Trust:

 

We have audited the accompanying statements of assets,liabilities and trust corpus of Eastern American Natural Gas Trust (the “Trust”)as of December 31, 2004 and 2003, and the related statements ofdistributable income, and changes in trust corpus for each of the three yearsin the period ended December 31, 2004. These financial statements are the responsibility of the Trustee.  Our responsibility is to express an opinionon these financial statements based on our audits.

 

We conducted our audits in accordance with thestandards of the Public Company Accounting Oversight Board (UnitedStates).  Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the financialstatements.  An audit also includesassessing the accounting principles used and significant estimates made by theTrustee, as well as evaluating the overall financial statementpresentation.  We believe that our auditsprovide a reasonable basis for our opinion.

 

As described in Note 2, these financial statementswere prepared on the basis of accounting prescribed by the Trust Agreement,which is a comprehensive basis of accounting other than accounting principlesgenerally accepted in the United States of America.

 

In our opinion, the financial statements referred toabove present fairly, in all material respects, the financial position of theTrust at December 31, 2004 and 2003, and the distributable income andchanges in trust corpus for each of the three years in the period ended December 31,2004, on the basis of accounting described in Note 2.

 

 
| /s/ PricewaterhouseCoopers LLP |   |
|--------------------------------|--------|

 

 

Pittsburgh, Pennsylvania

March 28, 2005

 

F-2

----

 

**EASTERN AMERICAN NATURAL GAS TRUST**

**STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS**

**as of December 31, 2004 and 2003**

 
| ** **                                                       | ** ** | **2004**    | ** ** | **2003**    | ** ** |
|------------------------------------------------------------------|------------|-------------|------------|-------------|------------|
|                                                             |       |        |       |        |       |
| Assets:                                                          |       |        |       |        |       |
|                                                             |       |        |       |        |       |
| Cash                                                             |       | $           | 185,752    |        | $          | 115,205 |   |
| Net Proceeds Receivable                                          |       | 3,989,827   |       | 2,678,769   |       |
| Net Profits Interests  in Gas Properties                         |       | 93,162,180  |       | 93,162,180  |       |
| Accumulated  Amortization                                        |       | (62,337,672 | )          | (58,519,514 | )          |
|                                                             |       |        |       |        |       |
| Total Assets                                                     |       | $           | 35,000,087 |        | $          | 37,436,640 |   |
|                                                             |       |        |       |        |       |
| Liabilities and Trust  Corpus:                                   |       |        |       |        |       |
|                                                             |       |        |       |        |       |
| Trust General and  Administrative Expenses Payable               |       | $           | 220,596    |        | $          | 161,772 |   |
| Distributions Payable                                            |       | 3,639,983   |       | 2,417,202   |       |
| Trust Corpus (5,900,000  Trust Units authorized and outstanding) |       | 31,139,508  |       | 34,857,666  |       |
|                                                             |       |        |       |        |       |
| Total Liabilities and  Trust Corpus                              |       | $           | 35,000,087 |        | $          | 37,436,640 |   |

 

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

 

F-3

----

 

**EASTERN AMERICAN NATURAL GAS TRUST**

**STATEMENTS OF DISTRIBUTABLE INCOME**

**for the years ended**

**December 31, 2004, 2003 and 2002**

 
| ** **                                                                  | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2002**   | ** ** |
|-----------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
|                                                                        |       |       |       |       |       |       |       |
| Royalty Income                                                              |       | $          | 14,449,208 |       | $          | 13,177,510 |       | $ | 9,024,646 |   |
|                                                                        |       |       |       |       |       |       |       |
| Operating Expenses:                                                         |       |       |       |       |       |       |       |
| Taxes on production and  property                                           |       | 989,430    |       | 897,881    |       | 613,115    |       |
| Operating cost charges                                                      |       | 519,228    |       | 510,032    |       | 501,738    |       |
|                                                                        |       |       |       |       |       |       |       |
| Total Operating  Expenses                                                   |       | 1,508,658  |       | 1,407,913  |       | 1,114,853  |       |
|                                                                        |       |       |       |       |       |       |       |
| Net Proceeds to the Trust                                                   |       | 12,940,550 |       | 11,769,597 |       | 7,909,793  |       |
|                                                                        |       |       |       |       |       |       |       |
| General and Administrative Expenses                                         |       | (1,002,397 | )          | (833,027   | )          | (594,921   | )          |
|                                                                        |       |       |       |       |       |       |       |
| Interest Income                                                             |       | 1,489      |       | 953        |       | 1,810      |       |
|                                                                        |       |       |       |       |       |       |       |
| Cash Proceeds on Sale of Net Profits Interests                              |       | 80,205     |       | 10,293     |       | 492,043    |       |
|                                                                        |       |       |       |       |       |       |       |
| Distributable Income                                                        |       | 12,019,847 |       | 10,947,816 |       | 7,808,725  |       |
|                                                                        |       |       |       |       |       |       |       |
| Cash Reserve                                                                |       | (100,000   | )          | (215,000   | )          | 0          |       |
|                                                                        |       |       |       |       |       |       |       |
| Distribution Amount                                                         |       | $          | 11,919,847 |       | $          | 10,732,816 |       | $ | 7,808,725 |   |
|                                                                        |       |       |       |       |       |       |       |
| Distributable Income Per Unit (5,900,000 Units  authorized and outstanding) |       | $          | 2.0373     |       | $          | 1.8556     |       | $ | 1.3235 |   |
|                                                                        |       |       |       |       |       |       |       |
| Distribution Amount Per Unit (5,900,000 units  authorized and outstanding)  |       | $          | 2.0203     |       | $          | 1.8191     |       | $ | 1.3235 |   |

 

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

* *

*F-4*

----

* *

**EASTERN AMERICAN NATURAL GAS TRUST**

**STATEMENTS OF CHANGES IN TRUST CORPUS**

**for the years ended**

**December 31, 2004, 2003 and 2002**

 
| ** **                                               | ** ** | **2004**    | ** ** | **2003**    | ** ** | **2002**   | ** ** |
|----------------------------------------------------------|------------|-------------|------------|-------------|------------|------------|------------|
|                                                     |       |        |       |        |       |       |       |
| Trust Corpus, Beginning of Period                        |       | $           | 34,857,666 |        | $          | 38,695,799 |       | $ | 43,169,981 |   |
| Distributable Income                                     |       | 12,019,847  |       | 10,947,816  |       | 7,808,725  |       |
| Distributions Paid or Payable to Unitholders             |       | (11,919,847 | )          | (10,732,816 | )          | (7,808,725 | )          |
| Amortization of Net Profits Interests in Gas  Properties |       | (3,818,158  | )          | (4,053,133  | )          | (4,474,182 | )          |
|                                                     |       |        |       |        |       |       |       |
| Trust Corpus, End of Period                              |       | $           | 31,139,508 |        | $          | 34,857,666 |       | $ | 38,695,799 |   |

* *

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

* *

*F-5*

----

* *

*EASTERN AMERICAN NATURAL GAS TRUST*

*NOTES TO FINANCIAL STATEMENTS*

* *

1.                                       Organizationof the Trust:

 

The Eastern American Natural Gas Trust (the “Trust”)was formed under the Delaware Business Trust Act pursuant to a Trust Agreement(the “Trust Agreement”) among Eastern American Energy Corporation (“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 Yorkacquired the corporate trust business of The Bank of Montreal TrustCompany.  As a result, The Bank of NewYork served as Trustee (the “Trustee”).  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. The appointment of JPMorgan Chase Bank, N.A. as successor trustee becameeffective as of January 1, 2005. Consequently, references herein to the “Trustee” mean JPMorgan ChaseBank, N.A. as successor trustee, on and after January 1, 2005.  References to the “Trustee” at any time priorto January 1, 2005 mean The Bank of New York as trustee.  Effective January 1, 2005, the transferagent for the Trust is Bondholder Communications.

 

The purpose of the Trust is to acquire and hold netprofits interests owned by Eastern American in 650 producing gas wells and 65proved development well locations in West Virginia and Pennsylvania (the “UnderlyingProperties”).  The Underlying Propertiesare operated by Eastern American.  TheNet Profits Interests (the “Net Profits Interests”) consist of a Royaltyinterest in 322 wells and a Term interest in the remaining wells andlocations.  Eastern American drilled 59of the 65 development wells.

 

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 December 31, 2004, 20,706 MMcf ofsuch gas had been produced.

 

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, subjectto 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.

 

Four (4) of the remaining six (6) development wellswere closely offset by third parties. 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 has agreed that, inlieu of drilling these closely offset development wells Eastern American canprovide the Trust, on an annual basis commencing on April 1, 1997, andover the remaining life of the Trust, a volume of gas which is equal to theprojected volumes of the wells as if they had been drilled.  These volumes have been estimated by theRyder Scott Company.

 

The two (2) remaining development wells were notdrilled because Eastern American was unable to cure various title defectsassociated with these wells.  EasternAmerican advised the Trust that it made a diligent effort to cure title but wasunsuccessful.  In West Virginia, an oiland gas well cannot be drilled unless a full and complete 100% leaseholdinterest is first obtained.  Drilling anoil and gas well without obtaining the entire leasehold estate would expose theoil and gas operator and the Trust to a possible suit for trespass.  Pursuant to the Term Net Profits InterestConveyance, if the state of title to the drill site to any development wellrenders such property undrillable in the good faith opinion of Eastern Americanunder the Reasonably Prudent Operator Standard then such drill site(s) shall beconstrued as a development well(s). Consequently, Eastern American has fulfilled its commitment to the Trustto drill the required number of development wells.

 

On March 15, 1993, 5,900,000 depositary unitswere issued in a public offering at an initial public offering price of $20.50per 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 

 

F-6

----

 

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 Treasury Obligations and $93,162,180 was paid toEastern American in consideration for the conveyance of the Net ProfitsInterests to the Trust.  The Trustacquired the Net Profits Interests effective as of January 1, 1993.  The Treasury Obligations are directly ownedby the Unitholders and are not part of the Trust Corpus. The TreasuryObligations are on deposit with the Trustee pursuant to the Deposit Agreement.

 

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 theproperties subject to the Net Profits Interests.  The Trust Agreement provides, among otherthings, that the Trust shall not engage in any business or commercial activityor acquire any asset other than the Net Profits Interests initially conveyed tothe Trust; the Trustee may establish a reserve for payment of any liabilitywhich is contingent, uncertain in amount or that is not currently due andpayable; the Trustee is authorized to borrow funds required to pay liabilitiesof the Trust, provided that such borrowings are repaid in full prior to furtherdistributions to Unitholders; and the Trustee will make quarterly cashdistributions to Unitholders from funds of the Trust.

 

F-7

----

 

2.                                       SignificantAccounting Policies:

 

The following is a summary of the significantaccounting policies followed by the Trust.

 

*Basis of Accounting:*

 

The financial statements of the Trust differ from financialstatements prepared in accordance with accounting principles generally acceptedin the United States of America due to the following; i) certain cash reservesmay be established for contingencies which were not accrued in the financialstatements; ii) amortization of the Net Profits Interests in gas properties ischarged directly to Trust Corpus; and iii) the sale of the Net ProfitsInterests is reflected in the Statements of Distributable Income as cashproceeds to the Trust.

 

*Cash:*

 

Cash consists of highly liquid instruments withmaturities at the time of acquisition of three months or less.

 

*Net Profits 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 awritedown is necessary to its investment in the Net Profits Interests in gasproperties to the extent that total capitalized costs, less accumulatedamortization, exceed undiscounted future net revenues attributable to provedgas reserves of the Underlying Properties. The Trust will then provide a writedown to the extent that the netcapitalized costs exceed the discounted future net revenues attributable toproved gas reserves of the Underlying Properties.  Any such writedown would not reducedistributable income, although it would reduce Trust Corpus.

 

Significant dispositions or abandonment of theUnderlying Properties are charged to Net Profits Interests and the TrustCorpus.

 

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 reduce distributable income, rather it ischarged directly to Trust Corpus. Revisions to estimated future units-of-production are treated on aprospective basis beginning on the date significant revisions are known.

 

The conveyance of the Royalty and Term Interests tothe Trust was accounted for as a purchase transaction.  The $93,162,180 reflected in the Statement ofAssets, Liabilities and Trust Corpus as Net Profits Interests represents5,900,000 Trust Units valued at $20.50 per depository unit less the $27,787,820paid for Treasury obligations.  Thecarrying value of the Trust’s investment in the Royalty Interests is notnecessarily indicative of the fair value of such Royalty Interests.

 

*Revenues and Expenses:*

 

The Trust serves as a pass-through entity, with items ofdepletion, interest income and expense, and income tax attributes being basedupon the status and election of the Unitholders.  Thus, the Statements of Distributable Incomepurport to show distributable income, defined as Trust income available fordistribution to Unitholders before application of those Unitholders’ additionalexpenses, if any, for depletion, interest income and expense, and income taxes.

 

The Trust uses the accrual basis to recognize revenue,with royalty income recorded as reserves are extracted from the UnderlyingProperties and sold.  Expenses are alsorecognized on an accrual basis. Operating expenses which include taxes onproduction and operating cost charges are recognized as incurred pursuant tothe Conveyances on a per well production basis. The payment provisions of the gas purchase contract between the Trustand Eastern Marketing Corporation require payment with respect to gasproduction for a calendar quarter to be made to the Trust on or before thetenth day of the third month following such quarter.

 

F-8

----

 

*Use of Estimates in the Preparation of FinancialStatements:*

 

The preparation of financial statements requires theTrust to make estimates and assumptions that affect the reported amounts ofassets and liabilities and the reported amounts of revenues and expenses duringthe reporting period.  Actual resultscould differ from those estimates.

 

*Segment Information:*

 

In 1998, the Trust adopted SFAS 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 the Trust’s net profitsinterests are located in the Appalachian region.

 

3.                                       IncomeTaxes:

 

Tax counsel to Eastern American advised EasternAmerican at the time of formation that, under then current tax laws, the Trustwould be classified as a grantor trust for federal and state income taxpurposes and, therefore, would not be subject to taxation at the Trustlevel.  The Trust continues to be taxexempt. Accordingly, no provision for federal or state income taxes has beenmade.  However, the opinion of taxcounsel is not binding on taxing authorities.

 

The Unitholders are considered, for income taxpurposes, to own the Trust’s income and principal as though no trust were inexistence.  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.                                       Distributionsto Unitholders:

 

The Trustee determines for each quarter the amountavailable for distribution to the Unitholders. Such amount will be equal to theexcess, if any, of the cash received by the Trust, on or before the tenth dayof the third month following the end of each calendar quarter ending prior tothe dissolution of the Trust, from the Net Profits Interests then held by theTrust attributable to production during such quarter, plus, with certainexceptions, any other cash receipts of the Trust during such quarter, over theliabilities of the Trust paid during such quarter, subject to adjustments forchanges made by the Trustee during such quarter in any cash reservesestablished at the discretion of the Trustee for the payment of contingent orfuture obligations of the Trust.  Cashreceived by the Trustee in a particular quarter from the Net Profits Interestswill reflect actual gas production for a portion of such quarter and aproduction estimate for the remainder of such quarter, such estimate to beadjusted to actual production in the following quarter.  In accordance with the Trust Agreement andDelaware law, Unitholders should be shielded from direct liability for anyenvironmental liabilities.  However,costs and expenses incurred by Eastern American for certain Capital Costsassociated with environmental liabilities arising after the effective date ofthe Conveyances would reduce Net Proceeds, and would therefore be borne, inpart, by the Unitholders.

 

Net Proceeds Receivable included in the Statements ofAssets, Liabilities and Trust Corpus as of December 31, 2004 are expectedto be received by the Trust and distributed to the Unitholders on March 16,2005.  The December 31, 2003 NetProceeds Receivable were received and distributed by the Trust on March 15,2004.

 

5.                                       RelatedParty Transactions:

 

The Trust is responsible for paying all legal,accounting, engineering and stock exchange fees, printing costs and otheradministrative expenses incurred at the direction of the Trustee.  The total of all Trustee fees and Trustadministrative expenses was $695,805 for the year ended December 31,2004,  $536,803 for the year ended December 31,2003, and $308,713 for the year ended December 31, 2002.  In accordance with the Trust Agreement, theTrustee pays Eastern American an annual fee which increases by 3.5% per year,payable quarterly, to reimburse Eastern American for overhead expenses. Theinitial fee at the inception of the Trust was $210,000.  The Trustee paid Eastern American $306,592,$296,224 and $286,208 for overhead expenses for 2004, 2003 and 2002respectively.  Operating cost chargesincluded in the Statements of Distributable Income are paid to EasternAmerican.

 

F-9

----

 

Gas production attributable to the Net ProfitsInterests is purchased from the Trust by Eastern Marketing Corporation (“EasternMarketing”), a wholly owned subsidiary of Eastern American, pursuant to a GasPurchase Contract which effectively commenced as of January 1, 1993 andexpires upon the termination of the Trust.

 

Pursuant to the Gas Purchase Contract, Eastern Marketingis obligated to purchase such gas production at a purchase price per Mcf equalto the greater of the Index Price, as defined below, or a Floor Price, for gasproduced in any quarter during the Primary Term, which ended December 31,1999.  Effective January 1, 2000,Eastern Marketing is obligated to purchase such gas production at a purchaseprice per Mcf equal to the Index Price for gas produced in any quarter afterthe Primary Term.

 

The Index Price for any quarter subsequent to thePrimary Term, which expired December 31, 1999, is determined solely byreference to the Variable Price component. 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.

 

Under a standby performance agreement Eastern Americanhas agreed to make payments under the Gas Purchase Contract to the extent suchpayments are not made by Eastern Marketing.

 

6.                                       SupplementalReserve Information (Unaudited):

 

Information regarding estimates of the proved gasreserves attributable to the Trust are based on reports prepared by independentpetroleum engineering consultants.  Suchestimates were prepared in accordance with guidelines established by theSecurities and Exchange Commission. Accordingly, the estimates were based on existing economic and operatingconditions.  Numerous uncertainties areinherent in estimating reserve volumes and values and such estimates aresubject to change as additional information becomes available.

 

The reserves actually recovered and the timing ofproduction of these reserves may be substantially different from the originalestimates.

 

The standardized measure of discounted future net cashflows was determined based on reserve estimates prepared by the independentpetroleum engineering consultants.  Fixedgas prices were used during the Primary Term, which ended December 31,1999.  The gas prices used thereafter arebased solely on the fourth quarter Variable Price component.

 

The reserves and revenue values for the UnderlyingProperties transferred to the Trust were estimated from projections of reservesand revenue values attributable to the combined Eastern American and Trustinterests in these properties.  Reservequantities are calculated differently for the Net Profits Interests becausesuch interests do not entitle the Trust to a specific quantity of gas but to 90percent of the Net Proceeds derived therefrom. Accordingly, there is no precise method of allocating estimates of thequantities of proved reserves between those held by the Trust and the intereststo be retained by Eastern American.  Forpurposes of this presentation, the proved reserves attributable to the NetProfits Interests have been proportionately reduced to reflect the futureestimated costs and expenses deducted in the calculation of Net Proceeds withrespect to the Net Profits Interests. The reserves presented for the Net Profits Interests reflect quantitiesof gas that are free of future costs or expenses.  The allocation of proved reserves between theTrust and Eastern American will vary in the future as relative estimates offuture gross revenues and future costs and expenses vary.

 

F-10

----

 

The royalty portion of the Net Profits Interests wascalculated beyond the liquidation date of the Trust (May 15, 2013), even thoughthe terms of the Trust Agreement require that the Royalty Net Profits Interestbe sold by the Trustee on or about this date and a liquidating distributionfrom the sales proceeds from such sale would be made to the Unitholders.  The Term Net Profits Interests was limited tothe 20-year period as defined by the Trust Agreement.

 

F-11

----

 

The following tablereconciles the change in proved reserves attributable to the Trust’s share ofthe Net Profits Interests (“NPI”) from January 1, 2002 to December 31,2004:

 
| ** **                      | ** ** | **Royalty** | ** ** | **Term**   | ** ** | **Total**  | ** ** |
|---------------------------------|------------|-------------|------------|------------|------------|------------|------------|
| ** **                      | ** ** | **NPI**     | ** ** | **NPI**    | ** ** | **NPI**    | ** ** |
| ** **                      | ** ** | **(MMcf)**  | ** ** | **(MMcf)** | ** ** | **(MMcf)** | ** ** |
|                            |       |        |       |       |       |       |       |
| Balance, January 1, 2002   |       | 12,904      |       | 9,841      |       | 22,745     |       |
|                            |       |        |       |       |       |       |       |
| Production                      |       | (1,034      | )          | (1,324     | )          | (2,357     | )          |
| Revisions of previous estimates |       | (155        | )          | (92        | )          | (246       | )          |
|                            |       |        |       |       |       |       |       |
| Balance, December 31, 2002 |       | 12,025      |       | 8,609      |       | 20,634     |       |
|                            |       |        |       |       |       |       |       |
| Production                      |       | (932        | )          | (1,229     | )          | (2,161     | )          |
| Revisions of previous estimates |       | 201         |       | 87         |       | 288        |       |
|                            |       |        |       |       |       |       |       |
| Balance, December 31, 2003 |       | 11,294      |       | 7,467      |       | 18,761     |       |
|                            |       |        |       |       |       |       |       |
| Production                      |       | (910        | )          | (1,158     | )          | (2,068     | )          |
| Revisions of previous estimates |       | 1,072       |       | 393        |       | 1,464      |       |
|                            |       |        |       |       |       |       |       |
| Balance, December 31, 2004 |       | 11,456      |       | 6,702      |       | 18,158     |       |

 

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

 
| ** **             | ** ** | **Royalty** | ** ** | **Term**   | ** ** | **Total**  | ** ** |
|------------------------|------------|-------------|------------|------------|------------|------------|------------|
| ** **             | ** ** | **NPI**     | ** ** | **NPI**    | ** ** | **NPI**    | ** ** |
| ** **             | ** ** | **(MMcf)**  | ** ** | **(MMcf)** | ** ** | **(MMcf)** | ** ** |
|                   |       |        |       |       |       |       |       |
| December 31, 2002 |       | 12,025      |       | 8,609      |       | 20,634     |       |
|                   |       |        |       |       |       |       |       |
| December 31, 2003 |       | 11,294      |       | 7,467      |       | 18,761     |       |
|                   |       |        |       |       |       |       |       |
| December 31, 2004 |       | 11,456      |       | 6,702      |       | 18,158     |       |

 

F-12

----

 

Standardized Measure of Discounted Future Net CashFlows Relating to Proved Reserves:

 

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

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

 

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

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

 

The following is the standardized measure ofdiscounted future net cash flows as of December 31, 2002 (in thousands):

 
| ** **                                                | ** ** | **Royalty** | ** ** | **Term** | ** ** | **Total** | ** ** |
|-----------------------------------------------------------|------------|-------------|------------|----------|------------|-----------|------------|
| ** **                                                | ** ** | **NPI**     | ** ** | **NPI**  | ** ** | **NPI**   | ** ** |
|                                                      |       |        |       |     |       |      |       |
| Future cash inflows                                       |       | $           | 69,983     |     | $          | 44,562    |       | $ | 114,545 |   |
| Future production taxes                                   |       | (3,839      | )          | (2,104   | )          | (5,943    | )          |
| Future production costs                                   |       | (12,400     | )          | (3,986   | )          | (16,386   | )          |
|                                                      |       |        |       |     |       |      |       |
| Future net cash inflows                                   |       | 53,743      |       | 38,472   |       | 92,215    |       |
| 10% discount factor                                       |       | (30,790     | )          | (13,114  | )          | (43,904   | )          |
|                                                      |       |        |       |     |       |      |       |
| Standardized measure of discounted future net cash  flows |       | $           | 22,953     |     | $          | 25,358    |       | $ | 48,311 |   |

 

F-13

----

 

Changes in Standardized Measure of Discounted FutureNet Cash Flows:

 

The following schedule reconciles the changesduring 2002, 2003 and 2004 in the standardized measure of discounted future netcash flows relating to proved reserves (in thousands):

 
| ** **                                   | ** ** | **Royalty** | ** ** | **Term** | ** ** | **Total** | ** ** |
|----------------------------------------------|------------|-------------|------------|----------|------------|-----------|------------|
| ** **                                   | ** ** | **NPI**     | ** ** | **NPI**  | ** ** | **NPI**   | ** ** |
|                                         |       |        |       |     |       |      |       |
| Standardized measure, January 1, 2002   |       | $           | 20,009     |     | $          | 22,419    |       | $ | 42,428 |   |
| Net proceeds to the Trust                    |       | (4,610      | )          | (3,300   | )          | (7,910    | )          |
| Revisions of previous estimates              |       | (363        | )          | (215     | )          | (578      | )          |
| Accretion of discount                        |       | 2,001       |       | 2,242    |       | 4,243     |       |
| Net change in price and production costs     |       | 5,650       |       | 4,054    |       | 9,704     |       |
| Other                                        |       | 266         |       | 159      |       | 425       |       |
|                                         |       |        |       |     |       |      |       |
| Standardized measure, December 31, 2002 |       | $           | 22,953     |     | $          | 25,358    |       | $ | 48,311 |   |
| Net proceeds to the Trust                    |       | (7,085      | )          | (4,684   | )          | (11,770   | )          |
| Revisions of previous estimates              |       | 1           |       | 0        |       | 1         |       |
| Accretion of discount                        |       | 2,295       |       | 2,536    |       | 4,831     |       |
| Net change in price and production costs     |       | 7,405       |       | 4,926    |       | 12,331    |       |
| Other                                        |       | 1,788       |       | 956      |       | 2,745     |       |
|                                         |       |        |       |     |       |      |       |
| Standardized measure, December 31, 2003 |       | $           | 27,357     |     | $          | 29,092    |       | $ | 56,449 |   |
| Net proceeds to the Trust                    |       | (8,164      | )          | (4,776   | )          | (12,941   | )          |
| Revisions of previous estimates              |       | 4,498       |       | 1,649    |       | 6,148     |       |
| Accretion of discount                        |       | 2,736       |       | 2,909    |       | 5,645     |       |
| Net change in price and production costs     |       | 12,331      |       | 7,491    |       | 19,822    |       |
| Other                                        |       | (352        | )          | 1,425    |       | 1,073     |       |
|                                         |       |        |       |     |       |      |       |
| Standardized measure, December 31, 2004 |       | $           | 38,406     |     | $          | 37,790    |       | $ | 76,196 |   |

 

F-14

----

 

7.                                       QuarterlyFinancial Data (Unaudited):

 

The following is asummary of royalty income and distributable income per unit by quarter in 2004,2003 and 2002 (all amounts in thousands except Distributable income per unit):

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

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

 
| **2002**                      | ** ** | **Mar 31** | ** ** | **June 30** | ** ** | **Sept 30** | ** ** | **Dec 31** | ** ** | **Total** | ** ** |
|-------------------------------|------------|------------|------------|------------------|------------|-------------|------------|------------|------------|-----------|------------|
| ** **                    |       |       |       |             |       |        |       |       |       |      |       |
| Royalty income                |       | $          | 1,771      |             | $          | 2,192       |       | $          | 2,449      |      | $          | 2,612 |   | $ | 9,025 |   |
|                          |       |       |       |             |       |        |       |       |       |      |       |
| Distributable income          |       | $          | 1,663      |             | $          | 1,950       |       | $          | 2,030      |      | $          | 2,166 |   | $ | 7,809 |   |
|                          |       |       |       |             |       |        |       |       |       |      |       |
| Distributable income per unit |       | $          | 0.2819     |             | $          | 0.3305      |       | $          | 0.3440     |      | $          | 0.3671 |   | $ | 1.3235 |   |

 

F-15

----