**UNITEDSTATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

## **FORM 1O-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, 2003**                                                                                                                                                                                                     |
|------------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **OR**     |
| **o**      |   | **TRANSITION REPORT PURSUANT TO SECTION  13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION**                                                                                                                                                                                                                           |
|       |   | **PERIOD  FROM                          TO                               ** |

 

**Commissionfile number: 1-11748**

## ** **

## **Eastern American Natural GasTrust**

(Exact name ofregistrant as specified in its Charter)

 

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

 

 

**TheBank of New York**

**Careof BNY Midwest Trust Company**

**2North LaSalle Street, Suite 1020**

**Chicago,Illinois 60602**

(Address ofprincipal executive office) (Zip Code)

 

**(312)827-8500**

(Registrant’stelephone number, including area code)

 

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

 

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

 

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

 

**None**

 

Indicate by check mark whether the registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrant was required to file such reports) and (2) has been subjectto such filing requirements for the past 90 days: Yes  o   No  ý

 

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, and willnot be contained, to the best of the registrant’s knowledge, in definitiveproxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to this Form 10-K. ý

 

Indicate by check markwhether the registrant is an accelerated filer (as defined in Rule 12b-2 of theAct).  Yes  ý No  o

 

 

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(1)          The Registrantinadvertently did not file reports on Form 8-K for its 2003 quarterly pressreleases announcing quarterly distributable income and distribution amounts.

 

As of March 8, 2004,5,900,000 Units of Beneficial Interest in Eastern American Natural Gas Trusthave been issued, remain outstanding and are held by non-affiliates of theregistrant (the “Outstanding Units”). Of the Outstanding Units, 69,900 Units of Beneficial Interest have beenwithdrawn from trading by voluntary action of Holders and may not be tradedunless such Holders comply with certain requirements provided in the relatedTrust Agreement (the “Withdrawn Units”).

 

The aggregate marketvalue of the Outstanding Units minus the Withdrawn Units at the closing salesprice on March 8, 2004 of $23.93 was approximately $141 million.

 

Documents Incorporated By Reference:     None

 

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**TABLEOF CONTENTS**

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

 

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**PARTI**

 

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

 

**CautionaryStatement**

 

The Trustee, its officersor its agents on behalf of the Trustee may, from time to time, makeforward-looking statements (other than statements of historical fact).  In addition, this Report on Form 10-K maycontain forward-looking statements. When used herein, the words “anticipates,” “expects,” “believes,”“intends” or “projects” and similar expressions are intended to identifyforward-looking statements.  To theextent that any forward-looking statements are made, the Trustee is unable topredict future changes in gas prices, gas production levels, economic activity,legislation and regulation, and certain changes in expenses of the Trust.  In addition, the Trust’s future results ofoperations and other forward looking statements contained in this item andelsewhere in this report involve a number of risks and uncertainties.  As a result of variations in such factors,actual results may differ materially from any forward-looking statements.  Some of these factors are describedbelow.  The Trustee disclaims anyobligations to update forward looking statements and all such forward-lookingstatements in this document are expressly qualified in their entirety by thecautionary statements in this paragraph.

 

**Definitions**

 

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

 

The followingdescriptions of the Eastern American Natural Gas Trust (the “Trust”), theDepositary Units, the Net Profits Interests, the Underlying Properties and thecalculation of amounts payable to the Trust, are subject to and qualified intheir entirety by the more detailed provisions of the Trust Agreement, theDepositary Agreement, the Conveyances and the Gas Purchase Contract (each asdefined below), all of which are incorporated by reference as exhibits to thisForm 10-K and available upon request from The Bank of New York (the“Trustee”).  The information containedherein relating to the operations of the Underlying Properties, as well asinformation upon which the reserve figures and financial information containedherein were derived, was furnished to the Trust by Eastern American EnergyCorporation (“Eastern American”).

 

**DESCRIPTION OF THE TRUST**

 

The Trust was formedunder the Delaware Business Trust Act pursuant to a Trust Agreement (the “TrustAgreement”) among Eastern American, as grantor, Bank of Montreal Trust Company,as Trustee (“Trustee”), and Wilmington Trust Company, as Delaware Trustee (the“Delaware Trustee”).  Effective May 8,2000, The Bank of New York acquired the corporate trust business of the Bank ofMontreal Trust Company / Harris Trust. Consequently, The Bank of New York serves as Trustee.

 

The Trust was formed toacquire and hold net profits interests (the “Net Profits Interests”) created fromthe working interests owned by Eastern American in 650 producing gas wells and65 proved development well locations located in West Virginia and Pennsylvania(the “Underlying Properties”). A portion of the production from the wellsburdened by the Net Profits Interests was intended to be eligible for credits(“Section 29 Credits”) under the Internal Revenue Code of 1986 for productionof gas from Devonian shale or tight formations. The Net Profits Interests to beacquired consisted of a royalty interest in 322 wells and a term interest inthe remaining wells and locations. Eastern American was obligated to drill andcomplete, at its expense, 65 development wells (the “Development Wells”) on thedevelopment well locations conveyed to the Trust.  Eastern American has fulfilled its obligation with respect to thedrilling of the Development Wells (see Note 1 of Financial Statements attachedas Annex B).  After May 15, 2012 andprior to or on May 15, 2013 (the “Liquidation Date”), the Trustee is requiredto sell the remaining royalty interests and liquidate the Trust.

 

On March 15, 1993,5,900,000 Depositary Units were issued in a public offering at an initialpublic offering price of $20.50 per Depositary Unit. Each Depositary Unitconsists of beneficial ownership of one unit of beneficial interest (“TrustUnit”) in the Trust and a $20 face amount beneficial ownership interest in a$1,000 face amount zero coupon United States Treasury obligation (“TreasuryObligation”) maturing on May 15, 2013. Holders of Depositary

 

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Units (“Unitholders”) may withdraw the Treasury Obligations associatedwith the Trust Units see “Description of Trust Units and Depositary Units”. Ofthe 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 wasretained 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.

 

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

 

The Trust is responsiblefor paying the Trustee’s fee and all legal, accounting, engineering and stockexchange fees, printing costs and other administrative expenses incurred by orat the direction of the Trustee.  Thetotal fees paid to the Trustee for 2003 were $45,000.  The total of all Trustee fees and Trust administrative expensesfor 2003 was $536,803.  Such costs couldfluctuate in the future depending primarily on the expenses the Trust incursfor professional services, particularly legal, accounting and engineeringservices.  In addition to such expenses,in 2003, the Trust paid Eastern American an overhead reimbursement of$296,224.  The overhead reimbursementincreases by 3.5% per year and is payable quarterly.

###### ** **

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

 

**The Conveyances**

 

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

 

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

 

The Royalty NPI is notlimited in term or amount. Under the Trust Agreement, the Trustee is directedto sell all remaining Royalty NPI after May 15, 2012 and prior to May 15, 2013,and net proceeds from selling such Royalty NPI will be distributed toUnitholders on the first quarterly payment date following the receipt of suchproceeds by the Trust. The Term NPI will expire on the earlier of May 15, 2013or such time as 41,683 MMcf of gas has been produced which is attributable toEastern American’s net revenue interests in the properties burdened by the TermNPI.  As of December 31, 2003, 19,548MMcf of such gas had been produced.

 

Eastern American can sellthe Underlying Properties, subject to and burdened by the Net ProfitsInterests, without the consent of the Trust or the Unitholders. In limitedcircumstances, Eastern American also can transfer the Underlying Properties andrequire the Trust to release the NPI burdening that property, without theconsent of the Trust or Unitholders, subject to payment to the Trust of thefair value of the interest released. In addition, any abandonment of

 

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a well included in the Underlying Properties or the Development Wellswill extinguish that portion of the Net Profits Interests that relate to suchwell.  See “Sale and Abandonment ofUnderlying Properties; Sale of Royalty NPI.”

 

**Calculation of Net Proceeds**

 

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

 

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

 

“Chargeable Costs” isthat volume of gas which equates in value, determined by reference to therelevant sales price under the Gas Purchase Contract or the Conveyances, asapplicable, to the sum of the “Operating Cost Charge”, “Capital Costs” and“Taxes” (as defined in the Conveyances).  The Operating Cost Charge for 2003 was $510,032, for 2002 was $501,738and for 2001 was $513,107.  In 2004 andsubsequent years, the Operating Cost Charge will increase based on increases inthe index of average weekly earnings of Crude Petroleum and Gas ProductionWorkers (published by the United States Department of Labor, Bureau of LaborStatistics), but not more than five percent (5%) per year and will not decreaseeven if the index decreases.  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’s working interestshare of capital costs for operations on the Underlying Properties having auseful life of at least three years, and excluding any capital costs incurredin drilling the Development Wells. Taxes refer to ad valorem taxes, production and severance taxes, andother taxes imposed on Eastern American’s or the Trust’s interests in theUnderlying Properties, or production therefrom.

 

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

 

The Conveyances require EasternAmerican to maintain books, records, and accounts sufficient to calculate thevolumes of gas and the share of Net Proceeds payable to the Trust. EasternAmerican provides to the Trust quarterly and annual statements of applicableproduction, revenues, and costs necessary for the Trust to prepare quarterlyand annual financial statements with respect to the Net Profits Interests andthe Underlying Properties. The financial statements of the Trust are auditedannually at the Trust’s expense.

 

**Gas Purchase Contract**

 

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

 

Under the Gas PurchaseContract, through the Primary Term ending December 31, 1999, Eastern Marketingpurchased gas from the Trust at an Index Price calculated based on a FixedPrice component (escalating at 5% a year and carrying a 66-2/3% weighting) anda Variable Price component (varying with the Henry Hub market price asdescribed below and carrying a 33-1/3% weighting), subject to a minimum FloorPrice (as defined in the Gas Purchase Contract).  Since January 1, 2000, and the end of the Primary Term, EasternMarketing has purchased gas from the Trust at an Index Price composed only ofthe Variable Price component, and not subject to any minimum Floor Price.  The Variable Price

 

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for any quarter is 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 Wall Street Journal,*forsuch contracts which expired in each of the five months prior to such month,(ii) the final settlement price per MMBtu for Henry Hub Gas Futures 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,*for suchcontracts which expire in each of the six months following such month.  A Henry Hub Gas Futures Contract is definedas a gas futures contract for gas to be delivered to the Henry Hub, which istraded on the New York Mercantile Exchange.

 

The purchase price paidto the Trust pursuant to the Gas Purchase Contract is a wellhead price andtitle to the gas purchased pursuant to the Gas Purchase Contract passes toEastern Marketing at the point of delivery. Payments to the Trust for gas purchased pursuant to the Gas PurchaseContract are made by Eastern Marketing on or before the tenth day of the thirdcalendar month following the end of each calendar quarter.

 

The Trust Agreementprovides that the Trustee may not agree to any amendment to the Gas PurchaseContract which would materially and adversely affect the revenues to the Trustwithout the approval of the holders of a majority of the outstanding TrustUnits. The Trust Agreement also provides that the Gas Purchase Contract may notbe terminated by the Trust without the approval of the holders of a majority ofthe outstanding Trust Units. The Gas Purchase Contract and the Trust Agreementhave been filed as exhibits to this Form 10-K by reference to materialspreviously filed with the Securities and Exchange Commission.  See Part IV, Item 15, “Exhibits, FinancialStatement Schedules, and Reports on Form 8-K”. The foregoing summary of theprincipal provisions of the Gas Purchase Contract, and certain provisions ofthe Trust Agreement, is qualified in its entirety by reference to the terms ofsuch agreements as set forth in such exhibits.

 

Eastern Marketing’srights and obligations under the Gas Purchase Contract are assignable undercircumstances where the assignee unconditionally assumes Eastern Marketing’sobligations under the Gas Purchase Contract, and then, only if such assignee(or assignee’s parent corporation if such parent guarantees the assignee’sobligations) has a rating assigned to its unsecured long-term debt by Moody’sInvestor Service of at least Baa+ and by Standard & Poor’s Corporation ofat least BBB-. Under such circumstances, Eastern Marketing and Eastern Americanwould be released from their obligations under the Gas Purchase Contract.

 

**Performance Support for Gas Purchase Contract**

 

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

 

**Distributions and Income Computations**

 

The Trustee determinesfor each quarter the amount of cash available for distribution to holders ofDepositary Units and the Trust Units evidenced thereby.  Such amount (the “Quarterly DistributionAmount”) is equal to the excess, if any, of (i) the cash that the Trustreceives on or before the tenth day of the third month after the end of eachcalendar quarter ending before the Trust is dissolved and that is attributableto production from the Net Profits Interest held by the Trust during thatcalendar quarter, plus, with certain exceptions, any other cash receipts of theTrust during such quarter, over (ii) the liabilities of the Trust paidduring such quarter, subject to adjustments for changes made by the Trusteeduring such quarter in any cash reserves established for the payment ofcontingent or future obligations of the Trust. Quarterly Distribution Amounts for each of the quarters in 2003 were$0.38, $0.52, $0.51, and $0.41 respectively. 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 QuarterlyDistribution Amount for each quarter is payable to Unitholders of record on thelast day of the second month following the end of such calendar quarter or suchlater date as the Trustee determines is required to comply with legal or stockexchange requirements (“Quarterly Record Date”).  It is expected that the Trustee will continue to be able todistribute

 

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cash on or before the 15th day (or the next succeeding business dayfollowing such day if such day is not a business day) of the third monthfollowing the end of each calendar quarter to each person who was a Unitholderof record on the Quarterly Record Date, together with interest earned on suchQuarterly Distribution Amount from the date of receipt thereof by the Trusteeto the payment date.

 

The net taxable income ofthe Trust for each calendar quarter is reported by the Trustee for tax purposesas belonging to the holders of record to whom the Quarterly Distribution Amountwas or will be distributed. Assuming that the Trust will be classified for taxpurposes as a “grantor trust,” the net taxable income will be realized by theholders for tax purposes in the calendar quarter received by the Trustee,rather than in the quarter distributed by the Trustee. Thus, a Unitholder’staxable income for a taxable year may differ from the cash the Unitholderreceives during that year. In addition, taxable income of a holder will differfrom the Quarterly Distribution Amount because the Treasury Obligations will betreated as generating interest income for tax purposes. There may also be minorvariances because of the possibility that, for example, a reserve will beestablished in one quarter that will not give rise to a tax deduction until asubsequent quarter, an expenditure paid for in one quarter will have to beamortized for tax purposes over several quarters, etc. See “Federal Income TaxMatters.”

 

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

** **

**Sale and Abandonment of Underlying Properties; Sale ofRoyalty NPI**

 

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

 

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

 

Eastern American may sellthe Underlying Properties, subject to and burdened by the Net ProfitsInterests, without the consent of the Trust or the Unitholders. In addition,prior to January 1, 2003, Eastern American could, without the consent of theTrust or the Unitholders, require the Trust to release Net Profits Interestsassociated with any well accounting for 0.25% or less of the total productionfrom the Underlying Properties in the prior 12 months, provided that, suchreleases cannot exceed five (5) wells during any 12 month period.  In addition until January 1, 2010, suchreleases cannot exceed an aggregate value to the Trust of $500,000 during any12 month period. Sales subsequent to that time may be made without regard todollar limitations. These releases will be made only in connection with a saleby Eastern American of the Underlying Properties and are conditioned upon theTrust receiving an amount equal to the fair value to the Trust of such NetProfits Interests (taking into account the existence of the Gas Purchase Contractwith respect to the gas attributable to the Net Profits Interests to bereleased). Any proceeds paid to the Trust are distributable to Unitholders forthe quarter in which they are received.

 

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

 

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**THE UNDERLYING PROPERTIES**

 

**General**

 

The Underlying Propertiesare comprised of Eastern American’s working interests in certain propertieslocated in the Appalachian Basin states of West Virginia and Pennsylvania.  As of December 31, 2003, such propertiesconsisted of 677 producing gas wells.  The working interests of Eastern American comprising the UnderlyingProperties are held under leases and farmout agreements with third parties.Such working interests are subject to landowner’s royalties (typically 12-1/2%)and may be subject to additional royalties or other obligations burdening theworking interests. Such royalties do not bear lease operating expenses, butreduce the revenue interests attributable to the Underlying Properties. EasternAmerican’s interests comprising the Underlying Properties represent, onaverage, a working interest of approximately 90% and a net revenue interest ofapproximately 76%.   As of December 31,2003, proved developed reserves attributable to the Net Profits Interests(reflecting quantities of gas free of future costs and expenses based onestimated prices) were approximately 22,710 MMcf. (See “Reserves”).

 

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

 

The Underlying Propertiesinitially included 65 specified development well locations for the drilling ofthe Development Wells by Eastern American. Eastern American was obligated tobear the costs of drilling and completing the Development Wells.  Eastern American has fulfilled itsobligation with respect to the drilling of the Development Wells.  (see Note 1 of Financial Statements attachedas Annex B)

 

Eastern American acquiredits interests in the Underlying Properties under or through (i) oil and gas leasesgranted by the mineral owner directly to Eastern American, (ii) assignments ofoil and gas leases by the lessee who originally obtained the leases from themineral owner, (iii) farmout agreements that grant Eastern American the rightto earn interests in the properties covered by such agreements by drillingwells and (iv) the acquisitions of oil and gas interests by Eastern American.

 

Production from the wellsto which the Underlying Properties relate is typically subject to, in onedegree or another, (i) landowner royalties and other burdens and obligationsretained under oil and gas leases, (ii) overriding royalty interests and (iii)interests of other working interest owners in the wells. The royalty andoverriding interests entitle the holders thereof to a certain percentage of theoil and gas produced from the wells or the proceeds therefrom and are generallydelivered free of all expenses of production but may be subject topost-production costs, such as production or gathering taxes, costs to treatthe gas to render it marketable, and certain transportation or gathering costs.Royalty interests are usually reserved by the lessor under an oil and gaslease. Overriding royalty interests are carved out of a lessee’s share ofproduction under an oil and gas lease and are generally reserved by apredecessor in title or reserved under farmout agreements.

 

A farmout agreement istypically an agreement under which a lessee under an oil and gas lease (the“Farmor”) grants to another party the right to drill wells on the tract coveredby such lease and to earn certain acreage for drilling such wells. In theAppalachian Basin, the Farmor generally receives a well location fee andreserves an overriding royalty interest in the wells which typically rangesfrom 3.25% to 6.25%. Farmout agreements typically provide that wells must bedrilled and completed as a condition to a transfer by the Farmor of theinterest in the underlying lease.

 

**Reserves**

 

*Proved Reserves of UnderlyingProperties and Net Profits Interests.*The following tablesets forth, as of December 31, 2003, certain estimated proved reserves,estimated future net revenues and the discounted present value thereofattributable to the Underlying Properties, the Royalty NPI and the Term NPI, ineach case derived from a report of oil and gas reserves attributable to theTrust as of December 31, 2003 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

 

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deducted in the calculation of Net Proceeds. Accordingly, the reservesattributable to the Net Profits Interests reflect quantities of gas that arefree of future costs or expenses if the price and cost assumptions set forth inthe Reserve Report occur. A decrease in the price assumption, or an increase inthe cost assumption used in the Reserve Report would reduce the estimates ofproved reserves, future net revenues and discounted future net revenues, setforth herein and in the Reserve Report. The Term NPI excludes production beyond the earlier of May 15, 2013 orsuch time as 41,683 MMcf of gas has been produced which is attributable toEastern American’s net revenue interests in the properties burdened by the TermNPI. The discounted present value of estimated future net revenues wasdetermined using a discount rate of 10% in accordance with existing securitieslaw requirements. A copy of the Reserve Report is included as Exhibit A hereto.

 
|                      |   | **Proved Gas  Reserves**   |   | **Estimated  Future NetRevenues(2)** |   | **Discounted  Estimated  Future NetRevenues(2)** |   |
|---------------------------|--------|----------------------------|--------|--------------------------------------|--------|--------------------------------------------------|--------|
|                      |   | **(MMcf)**                 |
|                      |   |                       |   |                                 |   |                                             |
|                      |   | **Developed**              |   | **Undeveloped**                      |   | **Total**                                        |
|                      |   |                       |   |                                 |   |                                             |   |   |   |   |   |
|                      |   | **(Dollars in thousands)** |   |
|                      |   |                       |   |                                 |   |                                             |   |   |   |   |   |
| Underlying  Properties(1) |   | 37,311                     |   | 0                                    |   | 37,311                                           |   | $ | 173,665 |   | $ | 71,622 |   |
|                      |   |                       |   |                                 |   |                                             |   |   |   |   |   |
| Net Profits  Interests:   |   |                       |   |                                 |   |                                             |   |   |   |   |   |
| Royalty NPI               |   | 14,142                     |   | 0                                    |   | 14,142                                           |   | $ | 64,646 |   | $ | 27,357 |   |
| Term NPI                  |   | 8,568                      |   | 0                                    |   | 8,568                                            |   | 42,743 |   | 29,092 |   |
|                      |   |                       |   |                                 |   |                                             |   |   |   |   |   |
| Total                     |   | 22,710                     |   | 0                                    |   | 22,710                                           |   | $ | 107,389 |   | $ | 56,449 |   |

 

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

 

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

 

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

 

**COMPETITION AND MARKETS**

 

All of the production attributable to the Net ProfitsInterest is sold to Eastern Marketing pursuant to the Gas Purchase Contract,under which, since January 1, 2000, all such production is purchased at apurchase price per Mcf equal to the Index Price, composed only of the VariablePrice.  See “The Net Profits Interests -Gas Purchase Contract.”

 

**REGULATION OF NATURAL GAS**

 

The natural gas industry has historically been highlyregulated by state and federal authorities. In the past, concerns about perceived pipeline monopolies and otherfactors caused Congress to impose economic regulation on both pipelines andproducers.  Federal agencies regulatedtariffs and conditions of service offered by interstate pipelines, and setmaximum prices on the wellhead price of natural gas sold into interstatecommerce.  States, and even localgovernments, also regulated retail sales of natural gas by localutilities.  Government agencies also setproduction rates to

 

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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 price controls or othersimilar economic regulations may not be reimposed in the future.

 

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

 

**HEALTH****, SAFETY,AND ENVIRONMENTAL REGULATION**

 

*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, or conditionsexisting on or under, the Underlying Properties before the effective date ofthe Conveyances will be borne by Eastern American and will not be deducted incalculating 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 the Unitholders.  The following subtopics discuss some of theprincipal forms of health, safety, and environmental regulation to which theUnderlying Properties and operations thereon are subject.  The costs of complying with these regulatoryrequirements may burden the Net Profits Interests to the extent they arise outof or are related to activities occurring on or in, or conditions existing onor under, the Underlying Properties after the effective date of theConveyances.

 

*Solidand Hazardous Waste.*The Underlying Properties includenumerous properties that have produced gas for a number of years but in whichEastern American has held an interest for a relatively short period of timeprior to the effective date of the Conveyances. Although, to Eastern American’sknowledge, prior operators utilized operating and disposal practices that werestandard in the industry at the time, hydrocarbons or other solid or hazardouswastes may have been disposed of or released on or under the UnderlyingProperties. Federal, state and local laws applicable to gas-related wastes havebecome increasingly more stringent. Under current laws, Eastern American or theoperator of the Underlying Properties could be required to remove or remediatepreviously disposed wastes or property contamination (including groundwatercontamination) or to perform remedial plugging operations to prevent futurecontamination.

 

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

 

*Superfund.*The 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, in somecases, private parties to take actions in response to threats to the publichealth or the environment and to seek recovery from such responsible classes ofpersons of the costs of such action. In the course of their operations, theoperators of the Underlying Properties have generated and will generate wastesthat may fall within CERCLA’s definition of “hazardous substances”.  Eastern

 

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American or the previous operator of the Underlying Properties may beresponsible under CERCLA for all or part of the costs to clean up sites atwhich such substances have been disposed.

 

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

 

*OSHA.*The operations of the Underlying Properties are subject tothe requirements of the Federal Occupational Safety and Health Act (“OSHA”) andcomparable state statutes. The OSHA hazard communication standard, the EPAcommunity right-to-know regulations under Title III of the Federal SuperfundAmendment and Reauthorization Act and similar state statutes require thatinformation be organized and maintained about hazardous materials used orproduced in the operations. Certain of this information must be provided toemployees, state and local government authorities and citizens.

 

**DESCRIPTION OF TRUST UNITS ANDDEPOSITARY UNITS**

 

The following information is subject to the detailedprovisions of the Deposit Agreement entered into by Eastern American, theTrustee, and Bank of Montreal Trust Company (The Bank of New York after May 8,2000), as Depositary (the “Depositary”) and all holders from time to time ofDepositary Units (the “Deposit Agreement”), which is incorporated by referenceas an exhibit to this Form 10-K and is available upon request.

 

The functions of the Depositary under the DepositAgreement are custodial and ministerial in nature and for the benefit ofUnitholders. The Deposit Agreement and the issuance of Depositary Unitsthereunder provide Unitholders an administratively convenient form of holdingan investment in the Trust and a Treasury Obligation. Each Depositary Unit isevidenced by a certificate, which is issued by the Depositary and transferableonly in denominations of 50 Depositary Units or an integral multiple thereof.Accordingly, each holder of 50 Depositary Units owns a beneficial interest in50 Trust Units and the entire beneficial interest in a discrete TreasuryObligation in a face amount of $1,000, or $20 per Depositary Unit.

 

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

 

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

 

**Withdrawal of Trust Units and Restrictions on Transfer**

 

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

 

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

 

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**Distributions and Income Computations**

 

The Trustee determines for each quarter the QuarterlyDistribution Amount available for distribution to holders of Depositary Unitsand the Trust Units evidenced thereby. The Quarterly Distribution Amount isequal to the excess, if any, (i) the cash that the Trust receives on or beforethe tenth day of the third month after the end of each calendar quarter endingbefore the Trust is dissolved and that is attributable to production from theNet Profits Interest held by the Trust during that calendar quarter, plus, withcertain exceptions, any other cash receipts of the Trust during such quarter,over (ii) the liabilities for the Trust paid during such quarter, subject toadjustments for changes made by the Trustee during such quarter in any cashreserves established for the payment of contingent or future obligations of theTrust. Based on the payment procedures relating to the Net Profits Interests,cash received by the Trustee in a particular quarter from the Net ProfitsInterests reflects 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. The QuarterlyDistribution Amount for each quarter is payable to Unitholders of record on theQuarterly Record Date, which is the last day of the second month following theend of such calendar quarter or such later date as the Trustee determines isrequired to comply with legal or stock exchange requirements. The Trusteegenerally is able to distribute cash on or before the 15th day (or the nextsucceeding business day following such day if such day is not a business day)of the third month following the end of each calendar quarter to each personwho was a Unitholder of record on the Quarterly Record Date, together withinterest earned on such Quarterly Distribution Amount from the date of receiptthereof by the Trustee to the payment date.

 

The net taxable income ofthe Trust for each calendar quarter is reported by the Trustee for tax purposesas belonging to the holders of record to whom the Quarterly Distribution Amountwas or will be distributed. Assuming that the Trust will be classified for taxpurposes as a “grantor trust,” the net taxable income will be realized by theholders for tax purposes in the calendar quarter received by the Trustee,rather than in the quarter distributed by the Trustee. Taxable income of aholder may differ from the Quarterly Distribution Amount because the TreasuryObligations will be treated as generating interest income for taxpurposes.  There may also be minorvariances because of the possibility that, for example, a reserve will beestablished in one quarter that will not give rise to a tax deduction until asubsequent quarter, an expenditure paid for in one quarter will have to beamortized for tax purposes over several quarters.  See “Federal Income Tax Matters”.

 

Each holder of Depositary Units (including theunderlying Trust Units) of record as of the record date for the final quarterof the Trust’s existence will be entitled to receive a liquidating distributionequal to a pro rata portion of the net proceeds from the sale of the RoyaltyNPI (to the extent not previously distributed) and a pro rata portion of theproceeds from the matured Treasury Obligations.

 

**Possible Divestiture of Depositary Units and Trust Units**

 

The Trust Agreementimposes no restrictions based on nationality or other status of holders ofTrust Units.  However, the TrustAgreement and the Deposit Agreement provide that in the event of certainjudicial or administrative proceedings seeking the cancellation or forfeitureof any property in which the Trust has an interest because of the nationality,citizenship, or any other status, of any one or more holders of Trust Unitsincluding holders of Depositary Units, the Trustee will give written noticethereof to each holder whose nationality, citizenship or other status is anissue in the proceeding, which notice will constitute a demand that such holderdispose of his Depositary Units or withdrawn Trust Units within 30 days. If anyholder fails to dispose of his Depositary Units or withdrawn Trust Units inaccordance with such notice, cash distributions on such units are subject tosuspension. In the event a holder fails to dispose of Depositary Units inaccordance with such notice, the Depositary may cancel such holder’s DepositaryUnits and reissue them in the name of the Trustee, whereupon the Trustee willuse its reasonable efforts to sell the Depositary Units and remit the net saleproceeds to such holder. In the case of Trust Units withdrawn from deposit withthe Depositary, the Trustee shall redeem such Trust Units not divested inaccordance with such notice, for a cash price equal to the then-current marketprice of the Depositary Units less the then-current over-the-counter bid priceof the related, withdrawn Treasury Obligations. The redemption price will bepaid out in quarterly installments limited to the amount that otherwise wouldhave been distributed in respect of such redeemed Trust Units.

 

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**Liability of Unitholders**

 

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

 

**Liquidation of the Trust**

 

The Trust will be liquidated and the Royalty NPI willbe sold prior to the Liquidation Date. Unitholders of record as of the recorddate for the final quarter of the Trust’s existence will be entitled to receivea terminating distribution with respect to each Depositary Unit equal to a prorata portion of the net proceeds from the sale of the Royalty NPI (to theextent not previously distributed) and a pro rata portion of the proceeds fromthe matured Treasury Obligations. Under the Trust Agreement, Eastern Americanhas a right of first refusal to purchase the Royalty NPI at fair market value,or if applicable the offered third-party price, prior to the Liquidation Date.

 

**FEDERAL INCOME TAX MATTERS**

 

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

 

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

 

At the issuance of the Depositary Units, EasternAmerican obtained an opinion of counsel for the benefit of the Trust, based oncertain representations and subject to certain qualifications, that, forFederal income tax purposes, (a) the Trust will be taxed as a grantor trust andnot as an association taxable as a corporation, (b) the Term NPI will be taxedas a production payment, (c) the income from the Royalty NPI will be royaltyincome subject to the allowance for depletion, and (d) a Unitholder will beeligible to claim Section 29 Credits with respect to certain sales of gasproduction attributable to the Royalty NPI. The Trustee has reported the operations of the Trust consistent withthese opinions.

 

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

 

**Reports**

 

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

 

**Treatment of Depositary Units**

 

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

 

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**Classification and Taxation of the Trust**

 

For federal income tax purposes, the Trust has beentreated and expects to continue to be treated not as an association taxable asa corporation, but as a grantor trust that is not subject to Federal income taxas an entity separate from its beneficial owners.  For tax purposes, Unitholders are considered to own and receivethe Trust’s assets and income as though no trust were in existence. The Trustfiles an information return, reporting all items of income, credit or deductionwhich must 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.

 

**Direct Taxation of Unitholders**

 

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

 

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

 

The Trust allocates income, deductions and credits toUnitholders based on record ownership at Quarterly Record Dates. The IRS couldrequire income and deductions of the Trust to be determined and allocated dailyor require some method of daily proration, which could result in an increase inthe administrative expenses of the Trust.

 

Under current market conditions, it is anticipatedthat total distributable cash will exceed taxable income through 2004. After2004, taxable income is anticipated to exceed distributable cash, and theamount of such excess could be significant. Such estimates are based onnumerous assumptions as to the allocation of a Unitholder’s purchase price andthe amount and treatment of operating costs, development costs, Trustadministrative expenses, production estimates and depletion. No assurance canbe given that the estimates will prove to be correct, and the actualrelationship between distributable cash and taxable income could be materiallyhigher or lower.

 

**Treatment of Trust Units**

 

On the assumption that the Trust is a grantor trustfor Federal income tax purposes, each Unitholder is treated as purchasingdirectly an interest in the Net Profits Interests. Purchasers of DepositaryUnits must allocate the portion of their total purchase price allocated to theTrust Unit between the Royalty NPI and the Term NPI in the proportion that thefair market value of each bears to the total fair market value of both.Information regarding purchase price allocations is furnished to Unitholders bythe Trustee.

 

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**Interest Income**

 

The Term NPI will be treated as a “production payment”under Section 636(a) of the Code.  Thus,Unitholders are treated as making a mortgage loan on the Underlying Propertiesof the Term NPI to Eastern American in an amount equal to the amount of thepurchase price of each Depositary Unit allocated to the Term NPI.  Because it is treated as a debt instrumentfor tax purposes, the Term NPI will be subject to the original issue discountincome (“OID”) rules of the Code which generally require the periodic inclusionof the original issue discount in income of the purchaser of a debtinstrument.  The Code also authorizesthe IRS to prescribe regulations modifying the statutory provisions where, byreason of contingent payments such as those provided for by the Term NPI, thetax treatment provided under the Code provisions does not carry out thepurposes of such provisions.

 

The IRS has issued a series of proposed and finalregulations dealing with debt instruments which call for contingentpayments.  The initial set of proposedregulations dealing with this topic were issued on April 8, 1986, and modifiedon February 26, 1991 (the “Old Proposed Regulations”).  A second set of proposed contingent paymentregulations were issued on January 19, 1993, but were withdrawn prior topublication in the Federal Register.  OnDecember 15, 1994, the IRS replaced the Old Proposed Regulations by issuing athird set of proposed regulations addressing debt obligations that provide forcontingent payments (the “New Proposed Regulations”).  The New Proposed Regulations were proposed to be effective fordebt obligations issued on or after the date that is sixty days following thepromulgation of the New Proposed Regulations in final form.  In this regard, the New Proposed Regulationshave been adopted in final form (the “Final Regulations”), though effectiveonly for debt instruments issued after August 12, 1996. Thus, by their terms,the New Proposed Regulations and the Final Regulations do not apply to the TermNPI.  However, the Preamble to the FinalRegulations provides that for debt instruments issued prior to the effectivedate of the Final Regulations, a taxpayer may use any reasonable method toaccount for such debt instruments, including a method that would have beenpermitted under the proposed regulations when the debt instrument was issued.

 

The Trustee understands that, in accordance with theforegoing, Eastern American, as obligor under the Term NPI, intends to continueto treat the Term NPI in the manner provided under the Old ProposedRegulations, which were proposed at the time the Term NPI was transferred tothe Trust and Trust Units were issued. Under this approach, each payment (at the time the amount of suchpayment becomes fixed) made to the Trust with respect to the Term NPI will betreated first as a payment of interest to the extent of interest deemed accruedunder the OID rules and the excess (if any) will be treated as a payment ofprincipal.  The total amount treated asprincipal will be limited to a portion of the purchase price of each DepositaryUnit allocated to the Term NPI.  Forpurposes of determining the amount of accrued interest, the Old ProposedRegulations required the use of the Applicable Federal Rate based on the duedate of the final payment due under the terms of the production payment, whichfor the Term NPI is May 15, 2013.

 

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

 

**Royalty Income and Depletion**

 

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

 

The allowance for depletion with respect to a propertyis determined annually and is the greater of cost depletion or, if allowable,percentage depletion. Percentage depletion is generally available to“independent producers” (generally persons who are not substantial refiners orretailers of oil or gas or their primary products) on the equivalent of 1,000 barrelsof production per day. Percentage depletion is a statutory allowance equal to15% of the gross income from production from a property which is included inincome by a taxpayer.

 

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Percentage depletion is subject to a net incomelimitation which is 100% of the taxable income from the property, computedwithout regard to depletion deductions and certain loss carrybacks. Ataxpayer’s total percentage depletion deduction for all properties for ataxable year is limited to 65% of the taxpayer’s taxable income for the year,before percentage depletion and certain other deductions. Unlike costdepletion, percentage depletion is not limited to the adjusted tax basis of theproperty, although it reduces that adjusted tax basis (but not below zero).

 

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

 

**Section 29 Credit**

 

Eastern American believes that most of the productionattributable to the Royalty NPI is gas produced from Devonian shale or a tightformation. Provided a number of requirements are met, taxpayers are entitled tothe Section 29 Credit for gas produced from Devonian shale or a tightformation. The Section 29 Credit generally applies only to gas produced fromDevonian shale or a tight formation in the United States and sold to anunrelated party prior to January 1, 2003, from wells drilled after December 31,1979, and prior to January 1, 1993. Additionally, the Section 29 Credit appliesonly 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 which isproduced from a well drilled after November 5, 1990. A Unitholder is eligibleto claim the Section 29 Credit with respect to certain sales of such gasattributable to the Royalty NPI.

 

Section 29 Credits resulting from an investment inDepositary Units may only be used to reduce a taxpayer’s regular income tax liabilityand generally may not be used to reduce a taxpayer’s liability for alternativeminimum tax. Section 29 Credits available to a taxpayer in any taxable year maynot be carried back but may be carried forward for use by that taxpayer in asubsequent tax year only in a limited fashion. See “Alternative Minimum Tax”below.

 

The Section 29 Credit is not available for productionafter December 31, 2002.  Congress inpast years has considered, without enacting, legislation to extend energy taxcredits such as the Section 29 Credit beyond their expiration date or to createnew similar credits.  The potentialeffect that enactment of any such possible legislation may have on Unitholdersin the future is unknown.

 

On March 23, 1999, the United States Tax Court ofAppeals for the Tenth Circuit affirmed a lower court decision in *True OilCompany v.*C.I.R. 170 F.3d 1294.  The Court ruled that, in order to beeligible for credits under Section 29 of the Internal Revenue Code, each wellfrom which gas is produced from Devonian shale or a tight formation mustreceive a determination from the Federal Energy Regulatory Commission (“FERC”)that the gas produced is, in fact, produced from Devonian shale or a tightformation.  Eastern American hasverified that most producing gas wells subject to the Royalty NPI have receiveda well category determination from FERC. Should the Internal Revenue Service challenge the amount of the Trust’sproduction qualifying for Section 29 Credits, a Unitholder might not be able toclaim the benefit of Section 29 credits for production attributable to awell that did not receive a FERC determination.  If successful, such a challenge could affect the tax reportingfor such credits for tax years examined by the IRS and any subsequent taxyears.  However, it should be noted thatunder current legislation the Section 29 credit is no longer available forproduction after December 31, 2002.

 

**Other Income and Expenses**

 

From time to time the Trust may generate interestincome on funds held as a reserve or held until the next distribution date.Expenses of the Trust include administrative expenses of the Trustee. Under theCode, certain miscellaneous itemized deductions of an individual taxpayer aredeductible only to the extent that in the aggregate they exceed 2% of thetaxpayer’s adjusted gross income. Certain administrative expenses attributableto the Trust Units may have to be aggregated with an individual Unitholder’sother miscellaneous itemized deductions to determine the excess

 

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over 2% of adjusted gross income. To date the amount of such expenseshas not been significant in relation to the Trust’s income.

 

**Alternative Minimum Tax**

 

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

 

A taxpayer is generally entitled to a credit against,or reduction in, his regular tax liability in a subsequent year in an amountequal to the AMT he pays for a prior taxable year. That credit can only be usedto reduce his regular tax liability for that subsequent year to the extent hisregular tax liability for that subsequent year exceeds his tentative minimumtax liability for that subsequent year, however.

 

The Section 29 Credit allowable to a taxpayer as areduction of his liability for any taxable year cannot exceed the excess of hisregular tax liability for such taxable year, as reduced by his foreign taxcredits and certain nonrefundable credits, over his tentative minimum taxliability for that year. Any amount of Section 29 Credit disallowed for the taxyear solely because of this limitation will increase a taxpayer’s credit forthe prior year’s AMT, as described above. There is no provision for thecarryback or carryforward of the Section 29 Credit in any other circumstances.Therefore, a Unitholder may not receive the full benefit of available Section29 Credits, depending on his particular AMT circumstances.

 

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

 

**Non-Passive Activity**

 

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

 

**Unrelated Business Taxable Income**

 

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

 

**Sale of Depositary Units; Sale of Trust Units or TreasuryObligations**

 

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

 

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For Federal income tax purposes, the sale of aDepositary Unit is treated as a sale by the Unitholder of his interest in theTreasury Obligations and the assets of the Trust. Thus, upon the sale ofDepositary Units, a Unitholder must treat as ordinary income his depletionrecapture amount, which is an amount equal to the lesser of (i) the gain onthat sale attributable to disposition of the Royalty NPI or (ii) the sum of theprior depletion deductions taken with respect to the Royalty NPI (but not inexcess of the initial basis of such Depositary Units allocated to the RoyaltyNPI). It is possible that the IRS would take the position that a portion of thesales proceeds is ordinary income to the extent of any accrued income at thetime of sale allocable to the Depositary Units sold, but which is not distributedto the selling Unitholder.

 

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

 

**Withdrawal of Trust Units or Treasury Obligations**

 

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

 

**Sale of Net 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 of proceedsdrawn from the letter of credit supporting Eastern Marketing’s obligationsunder the Gas Purchase Contract is, in certain cases, in consideration for theconveyance to Eastern Marketing of a production payment interest in reservesattributable to the Net Profits Interests or to compensate the Trust fordamages from a breach of the Gas Purchase Contract. All or a portion of suchproceeds may be treated as non-taxable loan proceeds attributable to a loan byEastern Marketing resulting from the production payment, may be treated asordinary income not subject to depletion or may receive some other treatment,depending upon facts existing at that time. To the extent receipt of suchproceeds is attributable to a sale of reserves by the Trust, depletion andSection 29 Credits available to the Unitholders for subsequent periods isreduced.

 

**Backup Withholding**

 

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

 

**Tax Shelter Registration**

 

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

 

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

 

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

 

**STATE TAX CONSIDERATIONS**

 

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

 

The Trust owns the Net Profits Interests burdening theUnderlying Properties located in the states of Pennsylvania and West Virginia.Both of these states have income taxes applicable to individuals and mayrequire the Trust to withhold taxes from distributions made to nonresidentUnitholders. Withholding, if required, is at the rate of 4% of taxable incomeattributable to West Virginia and 2.8% of taxable income attributable toPennsylvania. A Unitholder may be required to file state income tax returnsand/or to pay taxes in these states and may be subject to penalties for failureto comply with such requirements. Generally, Unitholders may treat state incometaxes that the Trust has withheld as having been paid by them to the state forwhich they were withheld.  Unitholdersmay be able to treat any taxes that they have paid or that have been withheldand paid to West Virginia or Pennsylvania as a deduction in computing Federalincome tax, or as a credit or a deduction in computing another state’s incometax.

 

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

 

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

 

**Available Information**

 

The Trust does not maintain an internet address or awebsite, and therefore does not make copies of its reports under the ExchangeAct available in that manner.  TheTrust’s filings under the Exchange Act are available electronically from thewebsite maintained by the Securities and Exchange Commission athttp://www.sec.gov.  The Trust will alsoprovide electronic copies of its recent filings free of charge upon request tothe Trustee, and will provide paper copies of its recent filings for its costsof reproduction upon request to the Trustee.

 

Item2.     *Properties.*

 

Reference is made to Item 1 of this Form 10-K.

 

Item3.     *LegalProceedings.*

 

None

 

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

 

There were no matters submitted to a vote ofUnitholders during the quarter ended December 31, 2003.

 

 

**PARTII**

 

**Item5****.     *Market forthe Registrant’s Common Equity, Related Unitholders Matters and IssuerPurchases of Equity Securities .***

 

The Depositary Units are traded on the New York StockExchange under the ticker symbol “NGT”. The high and low prices anddistributions paid during the quarters in the three-year period ended December31, 2003 were as follows:

 
| **Quarter**                    |   | **High** |   | **Low** |   | **Distributions  Paid** |   |
|--------------------------------|--------|----------|--------|---------|--------|-------------------------|--------|
| 2001:                          |   |     |   |    |   |                    |   |
| First (to March  31, 2001)     |   | $        | 18.25  |    | $      | 16.00                   |   | $ | 0.63 |   |
| Second (to June  30, 2001)     |   | $        | 19.95  |    | $      | 17.08                   |   | $ | 0.56 |   |
| Third (to  September 30, 2001) |   | $        | 19.44  |    | $      | 16.91                   |   | $ | 0.42 |   |
| Fourth (to  December 31, 2001) |   | $        | 19.38  |    | $      | 17.75                   |   | $ | 0.30 |   |
|                           |   |     |   |    |   |                    |   |
| 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 |   |

 

At March 8, 2004, the 5,900,000 Depositary Unitsoutstanding were held by approximately 298 Unitholders of record.

 

With respect to the Treasury Obligations, the high andlow closing prices per $1,000 face amount for the period from October 1, 2003to December 31, 2003 were $665.10 and $634.00, respectively.  The closing price on December 31, 2003 was$658.60 per $1,000 face amount.

 

During the fourth quarter of2003, there were no purchases of Units made by or on behalf of the Trust or any“affiliated purchaser” as defined in Rule 10b-18 (a) (3) under the ExchangeAct.

 

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**Item 6****. *SelectedFinancial Data.***

 
|                           |   | **December  31, 2003** |       | **December  31, 2002** |   | **December  31, 2001** |   | **December  31, 2000** |                   | **December  31, 1999** |   |
|--------------------------------|--------|------------------------|------------|------------------------|--------|------------------------|--------|------------------------|------------------------|------------------------|--------|
|                           |   |                   |       |                   |   |                   |   |                   |                   |                   |   |
| Distributable  Income          |   | $                      | 10,947,816 |                   | $      | 7,808,725              |   | $                      | 11,268,383             |                   | $      | 9,776,735 |   | $ | 8,561,984 |   |
| Distribution  Amount           |   | $                      | 10,732,816 |                   | $      | 7,808,725              |   | $                      | 11,268,383             |                   | $      | 9,776,735 |   | $ | 8,561,984 |   |
|                           |   |                   |       |                   |   |                   |   |                   |                   |                   |   |
| Distributable  Income per unit |   | $                      | 1.86       |                   | $      | 1.32                   |   | $                      | 1.91                   |                   | $      | 1.66 |   | $ | 1.45 |   |
| Distribution  Amount per unit  |   | $                      | 1.82       |                   | $      | 1.32                   |   | $                      | 1.91                   |                   | $      | 1.66 |   | $ | 1.45 |   |
|                           |   |                   |       |                   |   |                   |   |                   |                   |                   |   |
| Total assets at  year end      |   | $                      | 37,436,640 |                   | $      | 41,006,654             |   | $                      | 45,129,170   |                   | $      | 50,964,669 |   | $ | 55,251,901 |   |

 

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

 

**General**

 

The Trust does not conduct any operations oractivities.  The Trust’s purpose is, ingeneral, to hold the Net Profits Interests, to distribute to Unitholders cashwhich the Trust receives in respect of the Net Profits Interests and to performcertain administrative functions in respect of the Net Profits Interests andthe Depositary Units.  The Trust derivessubstantially all of its income and cash flows from the Net Profits Interests.

 

Under the Gas Purchase Contract, through the Primary Termending December 31, 1999, Eastern Marketing purchased gas from the Trust at anIndex Price calculated based on a Fixed Price component (escalating at 5% ayear and carrying a 66-2/3% weighting) and a Variable Price component (varyingwith the Henry Hub market price as described below and carrying a 33-1/3%weighting), subject to a minimum Floor Price (as defined in the Gas PurchaseContract).  Since January 1, 2000, andthe end of the Primary Term, Eastern Marketing has purchased gas from the Trustat an Index Price composed only of the Variable Price component, and notsubject to any minimum Floor Price.  TheVariable Price for any quarter is 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 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*, for such contractswhich expire during such month and (iii) the closing settlement price per MMBtuof Henry Hub Gas Futures Contracts determined as of the contract settlementdate for such month, as reported in *The Wall Street Journal*, for suchcontracts which expire in each of the six months following such month.  A Henry Hub Gas Futures Contract is definedas a gas futures contract for gas to be delivered to the Henry Hub which istraded on the New York Mercantile Exchange.

 

Accordingly, the pricepayable to the Trust for production may vary based on fluctuations in naturalgas futures prices during the relevant calculation period.  The price payable to the Trust will have adirect impact, positively or negatively, on the quarterly distributions payableby the Trust to the Unitholders.

 

During 2002, Eastern American was asked to sell 3wells in which the Trust owned a Net Profits Interest (the Western Pocahontas#7, #8 and #10 wells).  The partyseeking to purchase the wells owned the right to mine for coal on such properties(the “Coal Lessee”).  The Coal Lesseestated that the wells would materially interfere with the Coal Lessee’sproposed mining operations.

 

Eastern American reviewed the Trust Agreement andproduction from these wells, and determined that the Net Profits Interestassociated with the Western Pocahontas # 7 well accounted for more than 0.25%of the total production from the Underlying Properties for the prior twelve(12) month period.  Eastern Americanadvised the Coal Lessee that it could not sell this well.

 

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Subsequently, the Coal Lessee asserted that the coalestate in the relevant Underlying Properties was the dominate estate and thatunder the relevant oil and gas leases and applicable case law, the Coal Lesseecould cause the Trust and Eastern American to plug and abandon the well.  Eastern American and the Trust did notnecessarily agree with the Coal Lessee position, however, and in an effort toavoid litigation, the Trust and Eastern American entered into a SettlementAgreement and Release of All Claims with the Coal Lessee pursuant to whichEastern agreed to sell the Western Pocahontas # 7 well for the amount of$426,187.  The Trust’s share of theproceeds of $303,438 was included in Distributable Income to the Trust duringthe year ended December 31, 2002.  TheCoal Lessee purchased the two additional wells, the Western Pocahontas # 8 and#10 for the amount of $209,561.  TheTrust’s share of the proceeds of $188,605 was also included in the DistributableIncome of the Trust during the year ended December 31, 2002.

 

During 2003, a Coal Lessee contacted Eastern Americanand inquired as to whether it would sell the U.S. Steel Well # 26, which is awell in which the Trust owns a Net Profits Interests.  The Coal Lessee stated that the well would materially interferewith the Coal Lessee’s proposed mining operations.  Eastern American reviewed the Trust Agreement and production fromthis well to determine if it could cause the Trust to sell its Net ProfitsInterest in the well.  Upon review, itwas discovered that the Net Profits Interests associated with the U.S. Steel#26 well accounted for less 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 sell this well.  EasternAmerican received $11,437 for the sale of the U.S Steel Well #26.  The Trust’s share of the proceeds of $10,293was included in the Distributable Income of the Trust during the year endedDecember 31, 2003.

 

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

 

**CriticalAccounting Policies**

 

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

 

*Basis of Accounting:*

 

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

 

*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 reduce distributable income,although it would reduce Trust Corpus.

 

Amortization of the Net Profits Interests in gasproperties is calculated on a units-of-production basis, whereby the Trust’scost basis in the properties is divided by total Trust proved reserves toderive an amortization rate per reserve unit. Such amortization does not 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 Net Profits Interest impairment test and thedetermination of amortization rates are dependent on estimates of proved gasreserves attributable to the Trust. Numerous uncertainties are inherent in estimating reserve volumes andvalues, including economic and operating conditions, and such estimates aresubject to change as additional information becomes available.

 

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**Liquidity andCapital Resources**

 

The Trust has no source of liquidity or capitalresources other than the distributions received from the Net Profits Interests.

 

In accordance with the provisions of the Conveyances,generally all revenues received by the Trust, net of Trust administrativeexpenses and the amount of established reserves, are distributed currently tothe Unitholders.

 

The Trust did not have any contractual obligations asof December 31, 2003.  At December 31,2003, the Trust had accounts payable of $161,772 and distributions payable of$2,417,202.

 

#### **Results ofOperations**

#####  

##### 2003 Compared with 2002

 

The Trust’s distributable income was $10,947,816 for the twelve monthsended December 31, 2003 as compared to $7,808,725 for the twelve months endedDecember 31, 2002.  This increase wasdue to an increase in Royalty 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; $3.829 per Mcf for the twelve months endedDecember 31, 2002).  This increase wasoffset by a decrease in production of gas attributable to the Net ProfitsInterests for the twelve months ended December 31, 2003 (2,161 Mmcf) ascompared to the twelve 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 $613,115for the twelve months ended December 31, 2002. The increase in taxes is due directly to the increase in Royalty Incomeas discussed above. Trust general and administrative expenses were $833,027 forthe twelve months ended December 31, 2003 as compared to $594,921 for thetwelve months ended December 31, 2002. The increase in general and administrative expenses was due primarily toan increase in legal fees of $145,269 and an $81,042 increase due to the timingof payments for tax and audit services performed as well as an increase in feesfor such services.  The distributableincome includes Cash Proceeds on Sale of Net Profits Interests of $10,293 forthe period ended December 31, 2003, while $492,043 was recognized in thecorresponding prior twelve months.

 

During the twelve months ended December 31, 2003, the Trusteeestablished a cash reserve in the amount of $215,000 to facilitate the paymentof vendor invoices on a timely basis. No such reserve existed in the priortwelve months ended December 31, 2002. Establishing this reserve reduced distributions payable by $215,000 or$0.0365 per unit for the twelve months ended December 31, 2003. Amortization ofNets Profits Interests in Gas Properties was $4,053,133 for the twelve monthsended December 31, 2003 as compared to $4,474,182 for the twelve months endedDecember 31, 2002.  This decrease wasprimarily due to the decrease in production volumes.

 

The average price payable to the Trust for gas production attributableto the Net Profits Interests was $6.086 per Mcf for the twelve months endedDecember 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 corresponding twelvemonth period ended December 31, 2002 due to an increase in the average spotmarket price for gas delivered at the Henry Hub near Henry, Louisiana ($5.233per Dth for the twelve months ended December 31, 2003; $3.181 per Dth for thetwelve months ended December 31, 2002).

 

##### 2002 Compared with 2001

 

The Trust’s distributable income was $7,808,725 for the twelve monthsended December 31, 2002 as compared to $11,268,383 for the twelve months endedDecember 31, 2001.  This decrease wasdue to a decrease in Royalty Income for the twelve months ended December 31,2002 ($9,024,646) as compared to the twelve months ended December 31, 2001 ($13,260,202).  The decrease in Royalty Income was due to adecrease in the average price payable to the Trust under the Gas PurchaseContract as discussed below ($3.829 per Mcf for the twelve months endedDecember 31, 2002; $5.316 per Mcf for the twelve months ended December 31,2001).  This decrease was also due to adecrease in production of gas attributable to the Net Profits Interests for thetwelve months ended December 31, 2002 (2,357 Mmcf) as compared to the twelvemonths ended December 31, 2001 (2,489 Mmcf). The decline in production is primarily

 

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attributable tonatural production declines and the sale of wells.  Taxes on production and property were $613,115 for the twelvemonths ended December 31, 2002 as compared to $900,951 for the twelve monthsended December 31, 2001.  The decreasein taxes is due directly to the decrease in Royalty Income as discussed above.Trust general and administrative expenses remained relatively constant for thetwelve months ended December 31, 2002 as compared to the twelve months endedDecember 31, 2001.  The distributableincome includes Cash Proceeds on Sale of Net Profits Interests of $492,043 forthe period ended December 31, 2002, while no such sales were recognized in thecorresponding prior twelve months.

 

The average price payable to the Trust for gasproduction attributable to the Net Profits Interests was $3.829 per Mcf for thetwelve months ended December 31, 2002 as compared to $5.316 per Mcf for thetwelve months ended December 31, 2001. The average price per Mcf was lower for the twelve months ended December31, 2002 than the corresponding twelve month period ended December 31, 2001 dueto a decrease in the average spot market price for gas delivered at the HenryHub, near Henry, Louisiana ($3.181 per MMBtu for the twelve months endedDecember 31, 2002; $4.532 per MMBtu for the twelve months ended December 31,2001).

 

**Off-Balance SheetArrangements**

 

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

 

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

 

The Trust does not engage in any operations, and doesnot utilize market risk sensitive instruments, either for trading purposes orfor other than trading purposes.  Asdescribed in detail elsewhere herein, the Depositary Units consist ofbeneficial ownership of one unit of beneficial interest in the Trust and a $20face amount beneficial ownership interest in a $1,000 face amount zero couponTreasury Obligation maturing on May 15, 2013. High and low price information for the Treasury Obligations is includedunder Item 5.  As described in detailelsewhere herein, gas production attributable to the Net Profits Interest issold to a wholly owned subsidiary of Eastern American pursuant to the GasPurchase Contract described herein.

 

**Item 8****. *FinancialStatements and Supplementary Data.***

 
| Financial  Statements                                                                       |   |
|---------------------------------------------------------------------------------------------|--------|
| Report of Independent  Auditors                                                             |   |
| Statements  of Assets, Liabilities and Trust Corpus as of December 31, 2003 and 2002        |   |
| Statements of  Distributable Income for the years ended December 31, 2003, 2002 and 2001    |   |
| Statements of  Changes in Trust Corpus for the years ended December 31, 2003, 2002 and 2001 |   |
| Notes to Financial  Statements                                                              |   |

 

**Item9****. *Changes in and Disagreements with Accountants onAccounting and Financial Disclosure.***

 

None.

 

**Item9A**.  Controls and Procedures

 

**Evaluationof Disclosure Controls and Procedures**

 

The Trustee maintainsdisclosure controls and procedures designed to ensure that information requiredto be disclosed by the Trust in the reports that it files or submits under theExchange Act of 1934, as amended, is recorded, processed, summarized andreported within the time periods specified in the SEC’s rules andregulations.  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

 

22

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engineer to The Bank of New York, as Trustee of the Trust, and itsemployees who participate in the preparation of the Trust’s periodic reports asappropriate to allow timely decisions regarding required disclosure.

 

As of December 31, 2003,the Trustee carried out an evaluation of the Trustee’s disclosure controls andprocedures.  Patrick Tadie, a VicePresident of the Trustee, has concluded that the controls and procedures areeffective at the reasonable assurance level, while noting certain limitationson disclosure controls and procedures as set forth below.

 

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

 

•                  EasternAmerican and its consolidated subsidiaries manage (i) historical operatingdata, including production volumes, marketing of products, operating andcapital expenditures, environmental and other liabilities, the effects ofregulatory changes and the number of producing wells and acreage, (ii) plansfor future operating and capital expenditures and (iii) geological datarelating to reserves.  While the Trusteerequests material information for use in periodic reports as part of itsdisclosure controls and procedures, the Trustee does not manage thisinformation, and relies entirely on Eastern American to provide accurate andtimely information when requested for use in the Trust’s reports.

 

•                  Underthe terms of the Trust Agreement, the Trustee is entitled to, and in fact doesrely, upon certain experts in good faith, including (i) the independent reserveengineer with respect to the annual reserve report, which includes projectedproduction, operating expenses and capital expenses, and (ii) the independentauditors the Trustee has contracted with respect to the annual audit andquarterly reviews of financial data provided by Eastern American.  Other than contracting independent auditorsand reviewing the financial and other information provided to the Trust byEastern American on a quarterly basis, the Trustee makes no independent ordirect verification of this financial or other information. While the Trusteehas no reason to believe its reliance upon experts is unreasonable, thisreliance on experts and restricted access to information may be viewed as aweakness.

 

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

 

**Changes in Internal Controls**

 

To the knowledge of theTrustee, there have been no significant changes in the Trust’s internalcontrols that could significantly affect the Trust’s internal controls subsequentto the date the Trustee completed its evaluation.  The Trustee notes for purposes of clarification that it has noauthority over, and makes no statement concerning, the internal controls ofEastern American.

 

**PART III**

 

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

 

The Trust has nodirectors or executive officers.  TheTrustee is a corporate trustee which may be removed by the affirmative vote ofholders of a majority of the Trust Units then outstanding at a meeting of theUnitholders of the Trust at which a quorum is present.  The Trust is not required to and does nothold annual meetings of the Unitholders.

 

The Trust also does nothave an audit committee or body serving a similar function, and does not havean “audit committee financial expert”. The Trust has not adopted a code of ethics, as the Trust has nodirectors, officers, or employees.  TheTrust has not adopted a process by which Unitholders may communicate with BoardMembers, as the Trust has no board members or persons fulfilling a similarfunction.  Unitholders may contact theTrustee at the following address:

 

23

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The Bank of New York

Care of BNY Midwest TrustCompany

2 North LaSalle Street,Suite 1020

Chicago, Illinois 60602

 

**Item11****.         *ExecutiveCompensation.***

 

The Trust has no officers or directors, and isadministered by the Trustee.  For theyears ended December 31, 2003, 2002 and 2001, the Trustee received $45,000annually, as Trustee fees and $491,803, $263,713 and $261,662, respectively, asreimbursement of legal, accounting, and other professional expenses for suchservices.

 

**Item 12****.         *Security Ownership of Certain Beneficial Owners,Management and Related Unitholder Matters.***

 

(a)                                                          SecurityOwnership of Certain Beneficial Owners.

 

Basedon filings with the Securities and Exchange Commission, the Trust is not awareof any person owning beneficially more than five percent of the Units as ofMarch 1, 2004.

 

(b)                                                         SecurityOwnership of Management.

 

Not applicable.

 

(c)                                                          Changesin Control.

 

TheTrust knows of no arrangements, including the pledge of securities of theTrust, the operation of which may at a subsequent date result in a change incontrol of the Trust.

 

(d)                                                         Securitiesauthorized for issuance under equity compensation plans.

 

The Trust has no equity compensation plans andtherefore has not included tabular disclosures related thereto.

 

**Item 13****.          *CertainRelationships and Related Transactions.***

 

None.

 

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

 

**AuditFees**

 

The fees, including expenses, PricewaterhouseCoopersLLP billed the Trust for each of the last two fiscal years for professionalservices rendered in connections with the audits of the Trust’s annualfinancial statements and review of the Trust quarterly interim financialstatements were $83,500in 2002 and $73,000 in 2003.

 

**Audit-RelatedFees**

 

PricewaterhouseCoopers LLP did not bill the Trust anyadditional fees in the last two fiscal years for assurance and related servicesthat are reasonably related to the performance of the audit or review of theTrust’s Financial Statements.

 

**Tax Fees**

 

The fees, includingexpenses, PricewaterhouseCoopers LLP billed the Trust for each of the last twofiscal years for compliance, tax advice, or planning were $139,921in 2002 and$126,681 in 2003.

 

24

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**AllOther Fees**

 

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

 

**Pre-ApprovalPolicies**

 

The Trust does not have an audit committee or bodyperforming a similar function. Pre-approval of all services performed by PricewaterhouseCoopers LLPandapproval of the related fees is granted by the Trustee.

 

PART IV

 

**Item15****.****                            *Exhibits,Financial Statement Schedules, and Reports on Form 8-K.***

 
| Reports                                                                 | Page in this  Form 10-K |
|-------------------------------------------------------------------------|-------------------------|
| Reserve  Report of Ryder Scott Company, Independent Petroleum Engineers |                    |

 

Financial Statements

 

The followingfinancial statements are included in this Annual Report on Form 10-K on thepages indicated:

 
| Report of Independent  Auditors                                                             |   |
|---------------------------------------------------------------------------------------------|--------|
| Statements  of Assets, Liabilities and Trust Corpus as of December 31, 2003 and 2002        |   |
| Statements of  Distributable Income for the years ended December 31, 2003, 2002 and 2001    |   |
| Statements of  Changes in Trust Corpus for the years ended December 31, 2003, 2002 and 2001 |   |
| Notes to Financial Statements                                                               |   |

 

Schedules

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

 

Exhibits

Except as otherwise indicated below, all exhibits, except Exhibit 31.0and Exhibit 32.0, are incorporated herein by reference to the indicatedexhibits to filings previously made by the registrant with the Securities andExchange Commission.   All referencesare to the registrant’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                                                                         |   | 3.1                 |
| 4.1    |   | Specimen Depositary  Receipt                                                                                                                               |   | 4.1                 |
| 4.2    |   | Form of NPI Royalty  Deposit Agreement                                                                                                                     |   | 4.2                 |
| 10.1   |   | Form of Conveyance                                                                                                                                         |   | 10.1                |
| 10.2   |   | Form of Term NPI  Conveyance                                                                                                                               |   | 10.2                |
| 10.3   |   | Form of Gas Purchase  Contract between Eastern American Energy Corporation, Eastern American  Marketing Corporation and Eastern American Natural Gas Trust |   | 10.3                |
| 10.4   |   | Form of Conveyance of  Production Payment/Assignment of Production from Eastern American Natural Gas  Trust to Eastern American Marketing Corporation      |   | 10.4                |
| 10.5   |   | Form of Assignment and  Standby Performance Agreement                                                                                                      |   | 10.5                |
| 31.0   |   | Rule  13a-14(a)/15d-14(a) Certification                                                                                                                    |   |                |
| 32.0   |   | Section 1350  Certification                                                                                                                                |   |                |

 

25

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Reports on Form 8-K

 

None.

 

**SIGNATURES**

 

**Pursuant to the requirements ofSection 13 or 15(d) of the Securities Exchange Act of 1934, the registrant hasduly caused this report to be signed on its behalf by the undersigned,thereunto duly authorized on this  10thday of March, 2004.**

 
|   | EASTERN AMERICAN  NATURAL GAS TRUST |
|--------|-------------------------------------|
|   |                                |
|   | By:                                 | The Bank of New York,  Trustee |
|   |                                |   |
|   |                                |   |
|   | By:                                 | /s/ Patrick Tadie |   |
|   | Name:                               | Patrick Tadie |
|   | Title:                              | Vice President |

 

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

 

26

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[Ryder Scott Company,Independent Petroleum Engineers Letterhead]

 

January 21, 2004

 

 

Eastern American NaturalGas 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, 2003.  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 conveyedto the 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 income quantities presentedin this report are related to a large extent to hydrocarbon prices.  Hydrocarbon prices in effect at December 31,2003 were used in the preparation of this report as required by Securities andExchange Commission (SEC) and Financial Accounting Standards Bulletin No. 69(FASB 69) guidelines; however, actual future prices may vary significantly fromDecember 31, 2003 prices for reasons discussed in more detail in other sectionsof this report.  Therefore, quantitiesof reserves actually recovered and quantities of income actually received maydiffer significantly from the estimated quantities presented in this report.

 
|                  |   | **As of  December 31, 2003** |   |                                          |   |
|-----------------------|--------|------------------------------|--------|-----------------------------------------------|--------|
|                  |   | **Gas  (MMCF)**              |   | **Estimated  Future Net  Cash Inflows  (M$)** |   | **Present  Value  At 10%  (M$)** |   |
| Proved  Net Developed |   |                         |   |                                          |   |   |   |
|                  |   |                         |   |                                          |   |   |   |
| Royalty  NPI          |   | 14,142                       |   | 64,646                                        |   | 27,357 |   |
| Term  NPI             |   | 8,568                        |   | 42,743                                        |   | 29,092 |   |
| Total                 |   | 22,710                       |   | 107,389                                       |   | 56,449 |   |

 

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, 2004 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. The allocation of proved reserves of the Net Profits Interest betweenthe Trust and EAEC will vary in the future as relative estimates of futuregross revenues and future net incomes vary. Furthermore, EAEC requested that for purposes of our report the “RoyaltyNPI” be calculated beyond the Liquidation Date of May 15, 2013, even though bythe terms of the Trust Agreement the Royalty NPI will be sold by the Trustee onor about this date and a liquidating distribution of the sales proceeds fromsuch sale would be made to holders of Trust Units.  The Trust Agreement provides that the “Term NPI” entitles theTrust to receive the net proceeds from the gas produced from the propertiesburdened by the “Term NPI” until the earlier of May 15, 2013 or until such timeas 41,683 MMCF of gas has been produced. For purposes of this report, the “Term NPI” was limited to May 15, 2013.

 

A-1

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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 reservesof crude oil, natural gas, or natural gas liquids are estimated quantities thatgeological and engineering data demonstrate with reasonable certainty to berecoverable in the future from known reservoirs under existing conditions.  Reservoirs are considered proved if economicproducibility is supported by actual production or formation tests.  In certain instances, proved reserves may beassigned on the basis of a combination of core analysis and electrical andother type logs which indicate the reservoirs are analogous to reservoirs inthe same field which are producing or have demonstrated the ability to produceon a formation test.  The area of areservoir considered proved includes (1) that portion delineated by drillingand defined by fluid contacts, if any, and (2) the adjoining portions not yetdrilled that can be reasonably judged as economically productive on the basisof available geological and engineering data. In the absence of data on fluid contacts, the lowest known structuraloccurrence of hydrocarbons controls the lower proved limit of thereservoir.  Proved reserves areestimates of hydrocarbons to be recovered from a given date forward.  They may be revised as hydrocarbons areproduced and additional data becomes available. Proved natural gas reservesconsist of non-associated, associated and dissolved gas.  An appropriate reduction in gas reserves hasbeen made for the expected removal of natural gas liquids, for lease and plantfuel, and for the exclusion of non-hydrocarbon gases if they occur insignificant quantities.

 

Reserves that can be produced economically through theapplication of improved recovery techniques are included in the provedclassification when these qualifications are met:  (1) successful testing by a pilot project or the operation of aninstalled program in the reservoir provides support for the engineeringanalysis on which the project or program was based, and (2) it is reasonablycertain 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. Improved recovery also includes the enhanced recovery methods ofthermal, chemical flooding, and the use of miscible and immiscible displacementfluids.

 

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 proved reserves reasonably expected to be recovered throughexisting wells with existing equipment and operating methods, including (a)“developed producing reserves” which are those proved developed reservesreasonably expected to be produced from existing completion intervals now openfor production in existing wells, and (b) “developed non-producingreserves” which are those proved developed reserves which exist behind thecasing of existing wells which are reasonably expected to be produced throughthese wells in the predictable future where the cost of making suchhydrocarbons available for production should be relatively small compared tothe cost of a new well; and

 

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

 

A-2

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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 31,2003 from this report are presented in the following table:

 
|                      |   | **As of  December 31, 2003** |   |          |   |
|---------------------------|--------|------------------------------|--------|---------------|--------|
|                      |   | **Royalty  NPI**             |   | **Term  NPI** |   | **Totals** |   |
| Total  Proved             |   |                         |   |          |   |   |   |
| Future  Cash Inflows (M$) |   | 64,646                       |   | 42,743        |   | 107,389 |   |
| Future  Costs             |   |                         |   |          |   |   |   |
| Production  (M$)          |   | 0                            |   | 0             |   | 0 |   |
| Development  (M$)         |   | 0                            |   | 0             |   | 0 |   |
| Total  Costs (M$)         |   | 0                            |   | 0             |   | 0 |   |
|                      |   |                         |   |          |   |   |   |
| Future Net Cash Inflows   |   |                         |   |          |   |   |   |
| Before  Income Tax (M$)   |   | 64,646                       |   | 42,743        |   | 107,389 |   |
|                      |   |                         |   |          |   |   |   |
| Present  Value at 10%     |   |                         |   |          |   |   |   |
| Before  Income Tax (M$)   |   | 27,357                       |   | 29,092        |   | 56,449 |   |

 
|                             |   | **As of  December 31, 2003** |   |          |   |
|----------------------------------|--------|------------------------------|--------|---------------|--------|
|                             |   | **Royalty  NPI**             |   | **Term  NPI** |   | **Totals** |   |
| Proved  Net Developed Reserves   |   |                         |   |          |   |   |   |
| Gas  (MMCF)                      |   | 14,142                       |   | 8,568         |   | 22,710 |   |
|                             |   |                         |   |          |   |   |   |
| Proved  Net Undeveloped Reserves |   |                         |   |          |   |   |   |
| Gas  (MMCF)                      |   | 0                            |   | 0             |   | 0 |   |
|                             |   |                         |   |          |   |   |   |
| Total  Proved Net Reserves       |   |                         |   |          |   |   |   |
| Gas  (MMCF)                      |   | 14,142                       |   | 8,568         |   | 22,710 |   |

 

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. The effects of depreciation, depletion and federal income taxes have notbeen taken into account in estimating future net cash inflows.

 

EAEC furnished us gas prices in effect at December 31,2003 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 gasprices including 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 bedetermined by a weighted price consisting of two components during a primaryterm defined to begin on January 1, 1993 and end December 31, 1999.  The first component is the “Fixed” price whichhas been defined as $2.66 per Mcf beginning January 1, 1993.  This price escalates 5 percent per year onJanuary 1 of each year during the primary term beginning in 1994. The secondcomponent is the “Variable” price which for any quarter is equal to the HenryHub Average Spot Price (as defined) per MMBtu, plus $0.30 per MMBtu, multipliedby 110 percent to effect a Btu adjustment. The Henry Hub Average Spot Price is defined as the price per MMBtudetermined for any calendar quarter as the average price of the three months insuch quarter where each month’s

 

A-3

----

 

price is equal to the average of (i) the final settlement prices perMMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in the WallStreet Journal, for such contracts which expired in each of the five monthsprior to each month of such quarter, (ii) the final settlement price per MMBtufor Henry Hub Gas Futures Contracts, as reported in the Wall Street Journal,for such contracts which expire during such month and (iii) the closingsettlement prices per MMBtu of Henry Hub Gas Futures Contracts for such month,as reported in the Wall Street Journal, for such contracts which expirein each of the six months following such month.  A Henry Hub Gas Futures Contract is defined as a gas futurescontract for gas to be delivered to the Henry Hub which is traded on the NewYork Mercantile Exchange.  The weightedaverage price is determined by giving the “Fixed” price a 66 2/3 percentweighting and the variable price a 33 1/3 percent weighting.

 

Since the primary term is complete, the purchase priceunder the gas contract will be equal to the “Variable” price.  EAEC computed the “Variable” price under thegas contract as of December 31, 2003 as $5.724 per Mcf, utilizing $4.904 as theHenry Hub Average Spot Price computed in accordance with the gas contract.

 

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 usall of the accounts, records, geological and engineering data and reports andother data as were required for our investigation. The ownership interests,terms of the Trust, prices, taxes, and other factual data furnished to us inconnection with our investigation were accepted as represented.  The estimates presented in this report arebased on data available through March, 2003. The projections were developed forthe EAEC reserve report effective July 1, 2003.  EAEC has advised Ryder Scott that there has been no materialchange in the performance of these wells and therefore the July 1, 2003projections developed for the EAEC report were mechanically adjusted to January1, 2004 for use in this report.

 

At the time of formation of the Trust, EAEC assignedThe Trust an interest in 65 undeveloped locations.  During the period 1993 through 1998, EAEC has completed it’sdrilling obligation. A total of 59 wells were drilled over this period.  Two wells were not drilled due to titlefailure and four wells were not drilled due to short spacing.  Reserves and projections of futureproduction are included for the four locations which were not drilled due toshort spacing.

 

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 ofproved reserves may increase or decrease as a result of future operations ofEAEC.  Moreover, due to the nature ofthe Net Profits Interest, a change in the future costs, or prices differentfrom those projected herein may result in a change in the computed reserves andthe Net Proceeds to the Trust even if there are no revisions or additions tothe gross reserves attributed to the property.

 

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

 

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

 

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

 

A-4

----

 

Estimated NetReserve Data

Certain CombinedLeasehold Interests of

Eastern AmericaEnergy Corporation

And The Trust

As of December 31,2003

SEC Parameters

 
|                    |   | **Proved**    |   |            |   |
|-------------------------|--------|---------------|--------|-----------------|--------|
|                    |   | **Developed** |   | **Undeveloped** |   | **Total  Proved** |   |
| Net  Remaining Reserves |   |          |   |            |   |   |   |
|                    |   |          |   |            |   |   |   |
| Gas-MMCF                |   | 37,311        |   | 0               |   | 37,311 |   |

 

The estimated future net income associated with theforegoing volumes and the 10 percent discounted estimated future net income was$173,665,204 and $71,622,179, 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 AMERICANNATURAL GAS TRUST

 

----

 

FINANCIALSTATEMENTS

 

as of December 31,2003 and 2002

and for the yearsended

December 31, 2003,2002 and 2001

 

----

 

REPORTOF INDEPENDENT AUDITORS

 

 

To the Unitholders andThe Bank of New York,

As Trustee for EasternAmerican Natural Gas Trust:

 

We have audited theaccompanying statements of assets, liabilities and trust corpus of EasternAmerican Natural Gas Trust (the “Trust”) as of December 31, 2003 and 2002, andthe related statements of distributable income, and changes in trust corpus foreach of the three years in the period ended December 31, 2003.  These financial statements are theresponsibility of the Trustee.  Ourresponsibility is to express an opinion on these financial statements based onour audits.

 

We conducted our auditsin accordance with auditing standards generally accepted in the United Statesof America.  Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whetherthe financial statements are free of material misstatement.  An audit includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financialstatements.  An audit also includes assessingthe accounting principles used and significant estimates made by the Trustee,as well as evaluating the overall financial statement presentation.  We believe that our audits provide areasonable basis for our opinion.

 

As described in Note 2 tothe financial statements, these financial statements have been prepared on thebasis of accounting prescribed by the Trust Agreement.

 

In our opinion, thefinancial statements audited by us present fairly, in all material respects,the financial position of the Trust at December 31, 2003 and 2002, and thedistributable income and changes in trust corpus for each of the three years inthe period ended December 31, 2003, on the basis of accounting described inNote 2.

 

 
| /s/  PricewaterhouseCoopers LLP |   |
|---------------------------------|--------|
|                            |
|                            |
| Pittsburgh,  Pennsylvania       |
| March 5, 2004                   |

 

B-2

----

 

**EASTERN AMERICAN NATURAL GAS TRUST**

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

**as of December 31, 2003 and 2002**

 
|                                                             |   | **2003**    |       | **2002**    |   |
|------------------------------------------------------------------|--------|-------------|------------|-------------|--------|
|                                                             |   |        |       |        |   |
| Assets:                                                          |   |        |       |        |   |
|                                                             |   |        |       |        |   |
| Cash                                                             |   | $           | 115,205    |        | $      | 406 |   |
| Net Proceeds Receivable                                          |   | 2,678,769   |       | 2,310,449   |   |
| Net Profits Interests in Gas Properties                          |   | 93,162,180  |       | 93,162,180  |   |
| Accumulated Amortization                                         |   | (58,519,514 | )          | (54,466,381 | )      |
|                                                             |   |        |       |        |   |
| Total Assets                                                     |   | $           | 37,436,640 |        | $      | 41,006,654 |   |
|                                                             |   |        |       |        |   |
| Liabilities and Trust Corpus:                                    |   |        |       |        |   |
|                                                             |   |        |       |        |   |
| Trust General and Administrative Expenses Payable                |   | $           | 161,772    |        | $      | 145,098 |   |
| Distributions Payable                                            |   | 2,417,202   |       | 2,165,757   |   |
| Trust Corpus (5,900,000 Trust Units authorized and  outstanding) |   | 34,857,666  |       | 38,695,799  |   |
|                                                             |   |        |       |        |   |
| Total Liabilities and Trust Corpus                               |   | $           | 37,436,640 |        | $      | 41,006,654 |   |

 

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

 

B-3

----

 

**EASTERN AMERICAN NATURAL GAS TRUST**

 

**STATEMENTS OF DISTRIBUTABLE INCOME**

**for the years ended**

**December 31, 2003, 2002 and 2001**

 
|                                                                        |   | **2003**   |       | **2002**  |   | **2001**   |   |
|-----------------------------------------------------------------------------|--------|------------|------------|-----------|--------|------------|--------|
|                                                                        |   |       |       |      |   |       |   |
| Royalty Income                                                              |   | $          | 13,177,510 |      | $      | 9,024,646  |   | $ | 13,260,202 |   |
|                                                                        |   |       |       |      |   |       |   |
| Operating Expenses:                                                         |   |       |       |      |   |       |   |
| Taxes on production and property                                            |   | 897,881    |       | 613,115   |   | 900,951    |   |
| Operating cost charges                                                      |   | 510,032    |       | 501,738   |   | 513,107    |   |
|                                                                        |   |       |       |      |   |       |   |
| Total Operating Expenses                                                    |   | 1,407,913  |       | 1,114,853 |   | 1,414,058  |   |
|                                                                        |   |       |       |      |   |       |   |
| Net Proceeds to the Trust                                                   |   | 11,769,597 |       | 7,909,793 |   | 11,846,144 |   |
|                                                                        |   |       |       |      |   |       |   |
| General and Administrative Expenses                                         |   | (833,027   | )          | (594,921  | )      | (583,190   | )      |
|                                                                        |   |       |       |      |   |       |   |
| Interest Income                                                             |   | 953        |       | 1,810     |   | 5,429      |   |
|                                                                        |   |       |       |      |   |       |   |
| Cash Proceeds on Sale of Net Profits Interests                              |   | 10,293     |       | 492,043   |   | 0          |   |
|                                                                        |   |       |       |      |   |       |   |
| Distributable Income                                                        |   | 10,947,816 |       | 7,808,725 |   | 11,268,383 |   |
|                                                                        |   |       |       |      |   |       |   |
| Cash Reserve                                                                |   | (215,000   | )          | 0         |   | 0          |   |
|                                                                        |   |       |       |      |   |       |   |
| Distribution Amount                                                         |   | $          | 10,732,816 |      | $      | 7,808,725  |   | $ | 11,268,383 |   |
|                                                                        |   |       |       |      |   |       |   |
| Distributable Income Per Unit (5,900,000 units  authorized and outstanding) |   | $          | 1.8556     |      | $      | 1.3235     |   | $ | 1.9099 |   |
|                                                                        |   |       |       |      |   |       |   |
| Distribution Amount Per Unit (5,900,000 units authorized  and outstanding)  |   | $          | 1.8191     |      | $      | 1.3235     |   | $ | 1.9099 |   |

 

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

 

B-4

----

 

**EASTERN AMERICAN NATURAL GAS TRUST**

**STATEMENTS OF CHANGES IN TRUST CORPUS**

**for the years ended**

**December 31, 2003, 2002 and 2001**

 
|                                         |   | **2003**    |       | **2002**   |   | **2001**    |   |
|----------------------------------------------|--------|-------------|------------|------------|--------|-------------|--------|
|                                         |   |        |       |       |   |        |   |
| Trust Corpus, Beginning of Period            |   | $           | 38,695,799 |       | $      | 43,169,981  |   | $ | 47,650,950 |   |
| Distributable Income                         |   | 10,947,816  |       | 7,808,725  |   | 11,268,383  |   |
| Distributions Paid or Payable to Unitholders |   | (10,732,816 | )          | (7,808,725 | )      | (11,268,383 | )      |
| Amortization of Net Profits Interests in     |   |        |       |       |   |        |   |
| Gas Properties                               |   | (4,053,133  | )          | (4,474,182 | )      | (4,480,969  | )      |
|                                         |   |        |       |       |   |        |   |
| Trust Corpus, End of Period                  |   | $           | 34,857,666 |       | $      | 38,695,799  |   | $ | 43,169,981 |   |

 

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

 

B-5

----

 

EASTERN AMERICANNATURAL GAS TRUST

NOTES TO FINANCIALSTATEMENTS

 

1.             Organization of the Trust:

 

The Eastern AmericanNatural Gas Trust (the “Trust”) was formed under the Delaware Business TrustAct pursuant to a Trust Agreement (the “Trust Agreement”) among EasternAmerican Energy Corporation (“Eastern American”), as grantor, Bank of MontrealTrust Company, as Trustee, and Wilmington Trust Company, as Delaware Trustee(the “Delaware Trustee”).  Effective May8, 2000, The Bank of New York acquired the corporate trust business of The Bankof Montreal Trust Company.  As a result,The Bank of New York serves as Trustee (the “Trustee”).

 

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

 

Four (4) of the remainingsix (6) development wells were closely offset by third parties.  Since the wells drilled by the third partieswere within 1,000 feet of these development wells, Eastern American had a disagreementwith the Trust over Eastern American’s obligation to drill these closely offsetdevelopment wells.  The Trust has agreedthat, in lieu of drilling these closely offset development wells EasternAmerican can provide the Trust, on an annual basis commencing on April 1, 1997,and over the remaining life of the Trust, a volume of gas which is equal to theprojected volumes of the wells as if they had been drilled.  These volumes have been estimated by theRyder Scott Company.

 

The two (2) remainingdevelopment wells were not drilled because Eastern American was unable to curevarious title defects associated with these wells.  Eastern American advised the Trust that it made a diligent effortto cure title but was unsuccessful.  InWest Virginia, an oil and gas well cannot be drilled unless a full and complete100% leasehold interest is first obtained. Drilling an oil and gas well without obtaining the entire leaseholdestate would expose the oil and gas operator and the Trust to a possible suitfor trespass.  Pursuant to the Term NetProfits Interest Conveyance, if the state of title to the drill site to anydevelopment well renders such property undrillable in the good faith opinion ofEastern American under the Reasonably Prudent Operator Standard then such drillsite(s) shall be construed as a development well(s).  Consequently, Eastern American has fulfilled its commitment tothe Trust to drill the required number of development wells.

 

On March 15, 1993,5,900,000 depositary units were issued in a public offering at an initial publicoffering price of $20.50 per depositary unit. Each depositary unit consists of beneficial ownership of one unit ofbeneficial interest (“Trust Unit”) in the Trust and a $20 face amountbeneficial ownership interest in a $1,000 face amount zero coupon United StatesTreasury Obligation (“Treasury Obligation”) maturing on May 15, 2013 (see Note6).  Of the net proceeds from suchoffering, $27,787,820 was used to purchase $118,000,000 in face amount ofTreasury Obligations and $93,162,180 was paid to Eastern American inconsideration for the conveyance of the Net Profits Interests to theTrust.  The Trust acquired the NetProfits Interests effective as of January 1, 1993.

 

The Net Profits Interestsare passive in nature, and neither the Trustee nor the Delaware Trustee hasmanagement control or authority over, nor any responsibility relating to, theoperation of the properties 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.

 

B-6

----

 

2.                                                          SignificantAccounting Policies:

 

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

 

*Basis of Accounting:*

 

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

 

*Cash:*

 

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

 

*Net Profits Interests in Gas Properties:*

 

The Net Profits Interestsin gas properties are periodically assessed to determine whether their netcapitalized cost is impaired.  The Trustwill determine if a writedown is necessary to its investment in the Net ProfitsInterests in gas properties to the extent that total capitalized costs, lessaccumulated amortization, exceed undiscounted future net revenues attributableto proved gas reserves of the Underlying Properties.  The Trust will then provide a writedown to the extent that thenet capitalized costs exceed the discounted future net revenues attributable toproved gas reserves of the Underlying Properties.  Any such writedown would not reduce distributable income,although it would reduce Trust Corpus.

 

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

 

Amortization of the NetProfits Interests in gas properties is calculated on a units-of-productionbasis, whereby the Trust’s cost basis in the properties is divided by totalTrust proved reserves to derive an amortization rate per reserve unit.  Such amortization does not reducedistributable income, rather it is charged directly to Trust Corpus.  Revisions to estimated futureunits-of-production are treated on a prospective basis beginning on the datesignificant revisions are known.

 

The conveyance of the Royaltyand Term Interests to the Trust was accounted for as a purchasetransaction.  The $93,162,180 reflectedin the Statement of Assets, Liabilities and Trust Corpus as Net ProfitsInterests represents 5,900,000 Trust Units valued at $20.50 per depository unitless the $27,787,820 paid for Treasury obligations.  The carrying value of the Trust’s investment in the RoyaltyInterests is not necessarily indicative of the fair value of such RoyaltyInterests.

 

*Revenues and Expenses:*

 

The Trust serves as a pass-throughentity, with items of depletion, interest income and expense, and income taxattributes being based upon 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 theaccrual basis to recognize revenue, with royalty income recorded as reservesare extracted from the Underlying Properties and sold.  Expenses are also recognized on an accrualbasis. Operating expenses which include taxes on production and operating costcharges are recognized as incurred pursuant to the Conveyances on a per wellproduction basis.  The paymentprovisions of the gas purchase contract between the Trust and Eastern MarketingCorporation require payment with respect to gas production for a calendar quarterto be made to the Trust on or before the tenth day of the third month followingsuch quarter.

 

B-7

----

 

*Use of Estimates in the Preparation of Financial Statements:*

 

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

 

*Segment Information:*

 

In 1998, the Trust adopted SFAS 131, “Disclosure about Segments of anEnterprise and Related Information.” The Trust’s sole activity is earning royalty income from gas propertiesand, consequently, the Trust has only one operating segment, net profitsinterests in gas properties.  Substantiallyall of the Trust’s net profits interests are located in the Appalachian region.

 

3.             Income Taxes:

 

Tax counsel to the Trustadvised the Trust at the time of formation that, under then current tax laws,the Trust would be classified as a grantor trust for federal and state incometax purposes 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 tax counselis not binding on taxing authorities.

 

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

 

4.             Distributions to Unitholders:

 

The Trustee determinesfor each quarter the amount available for distribution to the Unitholders. Suchamount will be equal to the excess, if any, of the cash received by the Trust,on or before the tenth day of the third month following the end of eachcalendar quarter ending prior to the dissolution of the Trust, from the NetProfits Interests then held by the Trust attributable to production during suchquarter, plus, with certain exceptions, any other cash receipts of the Trustduring such quarter, over the liabilities of the Trust paid during such quarter,subject to adjustments for changes made by the Trustee during such quarter inany cash reserves established for the payment of contingent or futureobligations of the Trust.  Cash receivedby the Trustee in a particular quarter from the Net Profits Interests willreflect actual gas production for a portion of such quarter and a productionestimate for the remainder of such quarter, such estimate to be adjusted toactual production in the following quarter.

 

Net Proceeds Receivableincluded in the Statements of Assets, Liabilities and Trust Corpus as ofDecember 31, 2003 are expected to be received by the Trust and distributed tothe Unitholders on March 15, 2004 .  TheDecember 31, 2002 Net Proceeds Receivable were received and distributed by theTrust on March 17, 2003.

 

5.             Related Party Transactions:

 

The Trust is responsiblefor paying all legal, accounting, engineering and stock exchange fees, printingcosts and other administrative expenses incurred at the direction of theTrustee.  The total of all Trustee feesand Trust administrative expenses was $536,803 for the year ended December 31,2003,  $308,713 for the year endedDecember 31, 2002, and $306,662 for the year ended December 31, 2001.  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 $296,224,$286,208 and $276,528 for overhead expenses for 2003, 2002 and 2001respectively.  Operating cost chargesincluded in the Statements of Distributable Income are paid to EasternAmerican.

 

B-8

----

 

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

 

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

 

The Index Price for anyquarter subsequent to the Primary Term, which expired December 31, 1999, isdetermined solely by reference to the Variable Price component.  The Variable Price for any quarter is equalto the Henry Hub Average Spot Price (as defined) per MMBtu plus $0.30 perMMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. TheHenry Hub Average Spot Price is defined as the price per MMBtu determined forany calendar quarter equal to the price obtained with respect to each of thethree months in such quarter, in the manner specified below, and then takingthe average of the prices determined for each of such three months. The pricedetermined for any month of such quarter is equal to the average of (i) the finalsettlement prices per MMBtu for 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 WallStreet Journal,*for such contracts which expire during such monthand (iii) the closing settlement prices per MMBtu of Henry Hub Gas FuturesContracts determined as of the contract settlement date for such month, asreported in *TheWall Street Journal,*for such contracts which expire in each of thesix months following such month. A Henry Hub Gas Futures Contract is defined asa gas futures contract for gas to be delivered to the Henry Hub which is tradedon the New York Mercantile Exchange.

 

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

 

6.             Treasury Obligations:

 

The Treasury Obligationsare directly owned by the Unitholders and are not part of the Trust Corpus. TheTreasury Obligations are on deposit with the Trustee pursuant to the DepositAgreement.

 

The high and low closingprices of the Treasury Obligations, which have a $1,000 face principal amount,as quoted in the over-the-counter market for United States TreasuryObligations, are as follows:

 
|                              |   | **High** |   | **Low** |   |
|-----------------------------------|--------|----------|--------|---------|--------|
|                              |   |     |   |    |   |
| Quarter  ended March 31, 2001     |   | $        | 532.30 |    | $      | 501.20 |   |
| Quarter  ended June 30, 2001      |   | 524.90   |   | 494.30  |   |
| Quarter  ended September 30, 2001 |   | 549.30   |   | 503.70  |   |
| Quarter  ended December 31, 2001  |   | 577.70   |   | 513.60  |   |
|                              |   |     |   |    |   |
| Quarter  ended March 31, 2002     |   | $        | 548.40 |    | $      | 516.20 |   |
| Quarter  ended June 30, 2002      |   | 566.40   |   | 518.10  |   |
| Quarter  ended September 30, 2002 |   | 644.20   |   | 560.70  |   |
| Quarter  ended December 31, 2002  |   | 641.90   |   | 600.40  |   |
|                              |   |     |   |    |   |
| Quarter  ended March 31, 2003     |   | $        | 671.20 |    | $      | 618.30 |   |
| Quarter  ended June 30, 2003      |   | 711.50   |   | 641.50  |   |
| Quarter  ended September 30, 2003 |   | 684.00   |   | 620.30  |   |
| Quarter  ended December 31, 2003  |   | 665.10   |   | 634.00  |   |

 

B-9

----

 

On December 31, 2003, 2002 and 2001, the closing price of the TreasuryObligations, as quoted on such market, was $658.60, $637.10 and $526.10,respectively.

 

The Trust providesUnitholders with the option to separate the related Treasury Obligation fromthe Trust Units.  Upon exercising thisoption, the Unitholder receives the related Treasury obligation.  As of December 31, 2003 and 2002, thisoption was exercised on Trust Units of 77,900 and 107,900 respectively.

 

7.             Supplemental Reserve Information (Unaudited):

 

Information regardingestimates of the proved gas reserves attributable to the Trust are based onreports prepared by independent petroleum engineering consultants.  Such estimates were prepared in accordancewith guidelines established by the Securities and Exchange Commission.  Accordingly, the estimates were based onexisting economic and operating conditions. Numerous uncertainties are inherent in estimating reserve volumes andvalues and such estimates are subject to change as additional informationbecomes available.

 

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

 

The standardized measureof discounted future net cash flows was determined based on reserve estimatesprepared by the independent petroleum engineering consultants.  Fixed gas prices were used during thePrimary Term, which ended December 31, 1999. The gas prices used thereafter are based solely on the fourth quarterVariable gas price component.

 

The reserves and revenuevalues for the Underlying Properties transferred to the Trust were estimatedfrom projections of reserves and revenue values attributable to the combinedEastern American and Trust interests in these properties.  Reserve quantities are calculateddifferently for the Net Profits Interests because such interests do not entitlethe Trust to a specific quantity of gas but to 90 percent of the Net Proceedsderived therefrom.  Accordingly, thereis no precise method of allocating estimates of the quantities of provedreserves between those held by the Trust and the interests to be retained byEastern American.  For purposes of thispresentation, the proved reserves attributable to the Net Profits Interestshave been proportionately reduced to reflect the future estimated costs andexpenses deducted in the calculation of Net Proceeds with respect to the NetProfits Interests.  The reservespresented for the Net Profits Interests reflect quantities of gas that are freeof future costs or expenses.  Theallocation of proved reserves between the Trust and Eastern American will varyin the future as relative estimates of future gross revenues and future costsand expenses vary.

 

The royalty portion ofthe Net Profits Interests was calculated beyond the liquidation date of theTrust (May 15, 2013), even though the terms of the Trust Agreement require thatthe Royalty Net Profits Interest will be sold by the Trustee on or about thisdate and a liquidating distribution from the sales proceeds from such salewould be made to the Unitholders.  TheTerm Net Profits Interests was limited to the 20-year period as defined by theTrust Agreement.

 

B-10

----

 

The following tablereconciles the change in proved reserves attributable to the Trust’s share ofthe Net Profits Interests (“NPI”) from January 1, 2001 to December 31, 2003:

 
|                             |   | **Royalty  NPI  (MMcf)** |   | **Term  NPI  (MMcf)** |   | **Total  NPI  (MMcf)** |   |
|----------------------------------|--------|--------------------------|--------|-----------------------|--------|------------------------|--------|
|                             |   |                     |   |                  |   |                   |   |
| Balance,  January 1, 2001        |   | 14,983                   |   | 11,484                |   | 26,467                 |   |
|                             |   |                     |   |                  |   |                   |   |
| Production                       |   | (1,068                   | )      | (1,421                | )      | (2,489                 | )      |
| Revisions  of previous estimates |   | (1,011                   | )      | (222                  | )      | (1,233                 | )      |
|                             |   |                     |   |                  |   |                   |   |
| Balance,  December 31, 2001      |   | 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 |   | 3,049                    |   | 1,188                 |   | 4,237                  |   |
|                             |   |                     |   |                  |   |                   |   |
| Balance,  December 31, 2003      |   | 14,142                   |   | 8,568                 |   | 22,710                 |   |

 

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

 
|               |   | **Royalty  NPI  (MMcf)** |   | **Term  NPI  (MMcf)** |   | **Total  NPI  (MMcf)** |   |
|--------------------|--------|--------------------------|--------|-----------------------|--------|------------------------|--------|
|               |   |                     |   |                  |   |                   |   |
| December  31, 2001 |   | 12,904                   |   | 9,841                 |   | 22,745                 |   |
|               |   |                     |   |                  |   |                   |   |
| December  31, 2002 |   | 12,025                   |   | 8,609                 |   | 20,634                 |   |
|               |   |                     |   |                  |   |                   |   |
| December  31, 2003 |   | 14,142                   |   | 8,568                 |   | 22,710                 |   |

 

B-11

----

 

Standardized Measure ofDiscounted Future Net Cash Flows Relating to Proved Reserves:

 

The following is the standardized measure ofdiscounted future net cash flows as of December 31, 2003 (in thousands):

 
|                                                      |   | **Royalty  NPI** |   | **Term  NPI** |   | **Total  NPI** |   |
|-----------------------------------------------------------|--------|------------------|--------|---------------|--------|----------------|--------|
|                                                      |   |             |   |          |   |           |   |
| Future  cash inflows                                      |   | $                | 80,951 |          | $      | 49,043         |   | $ | 129,994 |   |
| Future  production costs                                  |   | (4,420           | )      | (2,333        | )      | (6,754         | )      |
| Future production taxes                                   |   | (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  NPI** |   | **Term  NPI** |   | **Total  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 |   |

 

The following is thestandardized measure of discounted future net cash flows as of December 31,2001 (in thousands):

 
|                                                      |   | **Royalty  NPI** |   | **Term  NPI** |   | **Total  NPI** |   |
|-----------------------------------------------------------|--------|------------------|--------|---------------|--------|----------------|--------|
|                                                      |   |             |   |          |   |           |   |
| Future  cash inflows                                      |   | $                | 61,197 |          | $      | 41,224         |   | $ | 102,421 |   |
| Future  production taxes                                  |   | (3,334           | )      | (1,916        | )      | (5,249         | )      |
| Future  production costs                                  |   | (11,924          | )      | (4,275        | )      | (16,199        | )      |
|                                                      |   |             |   |          |   |           |   |
| Future  net cash inflows                                  |   | 45,939           |   | 35,033        |   | 80,973         |   |
| 10%  discount factor                                      |   | (25,930          | )      | (12,614       | )      | (38,545        | )      |
|                                                      |   |             |   |          |   |           |   |
| Standardized  measure of discounted future net cash flows |   | $                | 20,009 |          | $      | 22,419         |   | $ | 42,428 |   |

 

B-12

----

 

Changes in StandardizedMeasure of Discounted Future Net Cash Flows:

 

The following schedule reconciles the changes during 2001, 2002 and2003 in the standardized measure of discounted future net cash flows relatingto proved reserves (in thousands):

 
|                                      |   | **Royalty  NPI** |       | **Term  NPI** |       | **Total  NPI** |       |
|-------------------------------------------|--------|------------------|------------|---------------|------------|----------------|------------|
|                                      |   |             | ** ** |          | ** ** |           | ** ** |
| Standardized  measure, January 1, 2001    |   | $                | 35,074     |          | $          | 39,646         |       | $ | 74,720 |   |
| Net  proceeds to the Trust                |   | (6,721           | )          | (5,125        | )          | (11,846        | )          |
| Revisions  of previous estimates          |   | (1,886           | )          | (414          | )          | (2,300         | )          |
| Accretion  of discount                    |   | 3,507            |       | 3,965         |       | 7,472          |       |
| Net  change in price and production costs |   | (13,327          | )          | (9,638        | )          | (22,965        | )          |
| Other                                     |   | 3,362            |       | (6,015        | )          | (2,653         | )          |
|                                      |   |             |       |          |       |           |       |
| Standardized  measure, December 31, 2001  |   | $                | 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                |   | (7,329           | )          | (4,440        | )          | (11,770        | )          |
| Revisions  of previous estimates          |   | 7,579            |       | 2,953         |       | 10,532         |       |
| Accretion  of discount                    |   | 2,295            |       | 2,536         |       | 4,831          |       |
| Net  change in price and production costs |   | 1,601            |       | 1,065         |       | 2,666          |       |
| Other                                     |   | 258              |       | 1,621         |       | 1,879          |       |
|                                      |   |             |       |          |       |           |       |
| Standardized  measure, December 31, 2003  |   | $                | 27,357     |          | $          | 29,092         |       | $ | 56,449 |   |

 

B-13

----

 

8.                                       QuarterlyFinancial Data (Unaudited):

 

The following is asummary of royalty income and distributable income per unit by quarter in 2003,2002 and 2001 (all amounts in thousands except Distributable income per unit):

 
| **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 |   |

 
| **2001**                       |   | **Mar 31** |   | **June 30** |   | **Sept 30** |   | **Dec 31** |   | **Total** |   |
|--------------------------------|--------|------------|--------|-------------|--------|-------------|--------|------------|--------|-----------|--------|
|                           |   |       |   |        |   |        |   |       |   |      |   |
| Royalty  income                |   | $          | 4,307  |        | $      | 3,840       |   | $          | 2,872  |      | $      | 2,241 |   | $ | 13,260 |   |
|                           |   |       |   |        |   |        |   |       |   |      |   |
| Distributable  income          |   | $          | 3,726  |        | $      | 3,311       |   | $          | 2,444  |      | $      | 1,787 |   | $ | 11,268 |   |
|                           |   |       |   |        |   |        |   |       |   |      |   |
| Distributable  income per unit |   | $          | 0.6315 |        | $      | 0.5612      |   | $          | 0.4143 |      | $      | 0.3029 |   | $ | 1.9099 |   |

 

B-14

----