**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

**FORM10-Q**

 

**(Mark One)**

| ý | ** ** | **QUARTERLY REPORT UNDER SECTION 13 OR 15 (d)  OF THE SECURITIES EXCHANGE ACT OF 1934**         |
|--------|------------|-------------------------------------------------------------------------------------------------|
|   |       |                                                                                            |
|   |       | **For the quarterly period ended September 30,  2005**                                          |
|   |       |                                                                                            |
|   |       | **OR**                                                                                          |
|   |       |                                                                                            |
| **o**  | ** ** | **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15  (d)  OF THE SECURITIES EXCHANGE ACT OF 1934** |
|   |       |                                                                                            |

 

**For thetransition period from           to           **

 

**Commission File Number 1-11748**

 

**EASTERN AMERICAN NATURAL GAS TRUST**

(Exact name of registrant as specified in its charter)

 
| **Delaware**                | **36-7034603**       |
|----------------------------------|----------------------|
| (State  or other jurisdiction of | (I.R.S.  Employer    |
| incorporation  or organization)  | Identification  No.) |

 

**JPMorgan Chase Bank, N.A., Trustee**

**Institutional Trust Services**

**700 Lavaca, 2nd Floor**

**Austin, Texas**

(Address of principal executive offices)

 

**78701**

(Zip Code)

 

**(****800)852-1422**

(Registrant’s telephone number, including area code)

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to filesuch reports) and (2) has been subject to such filing requirements for the past90 days.

Yes     o                No   ý

 

(1)   TheRegistrant inadvertently did not file a report on Form 8-K for its 2004  third quarter press release announcingquarterly distributable income and distribution amounts.

 

Indicate by check markwhether the registrant is an accelerated filer (as defined in Rule 12b-2 of theAct).

Yes     ý                No   o

 

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of theExchange Act).

Yes     o                No   ý

 

As of November 4, 2005,5,900,000 Units of Beneficial Interest in Eastern American Natural Gas Trustwere outstanding.

# ** **

# ** **

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# **PART I – FINANCIALINFORMATION**

 

**ITEM1.   Financial Statements**

 

**EASTERN AMERICAN NATURAL GAS TRUST**

 

**STATEMENTS OF DISTRIBUTABLE INCOME**

*(Unaudited)*

 
| ** **                                                                  | ** ** | **Nine Months Ended  September 30** | ** ** | **Three Months Ended  September 30** | ** ** |
|-----------------------------------------------------------------------------|------------|-------------------------------------|------------|--------------------------------------|------------|
| ** **                                                                  | ** ** | ** **                          | ** ** |
| ** **                                                                  | ** ** | **2005**                            | ** ** | **2004**                             | ** ** | **2005** | ** ** | **2004** | ** ** |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Royalty  Income                                                             |       | $                                   | 12,221,141 |                                 | $          | 10,024,331 |   | $ | 4,659,185 |   | $ | 3,452,442 |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Operating  Expenses                                                         |       |                                |       |                                 |       |   |   |   |   |
| Taxes on production and property                                            |       | 839,691                             |       | 683,658                              |       | 320,484 |   | 232,004 |   |
| Operating cost charges                                                      |       | 400,761                             |       | 389,950                              |       | 133,587 |   | 129,280 |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Total Operating Expenses                                                    |       | 1,240,452                           |       | 1,073,608                            |       | 454,071 |   | 361,284 |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Net Proceeds  to the Trust                                                  |       | 10,980,689                          |       | 8,950,723                            |       | 4,205,114 |   | 3,091,158 |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| General and  Administrative Expenses                                        |       | (1,017,252                          | )          | (651,903                             | )          | (405,340 | ) | (242,168 | ) |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Interest  Income                                                            |       | 500                                 |       | 838                                  |       | — |   | 405 |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Cash  Proceeds on Sale of Net Profits Interests                             |       | —                              |       | 80,205                               |       | — |   | — |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Distributable Income                                                        |       | 9,963,937                           |       | 8,379,863                            |       | 3,799,774 |   | 2,849,395 |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Cash Reserve                                                                |       | (185,000                            | )          | (100,000                             | )          | — |   | — |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Distribution Amount                                                         |       | $                                   | 9,778,937  |                                 | $          | 8,279,863 |   | $ | 3,799,774 |   | $ | 2,849,395 |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Distributable Income Per Unit (5,900,000 units  authorized and outstanding) |       | $                                   | 1.6888     |                                 | $          | 1.4203 |   | $ | 0.6440 |   | $ | 0.4829 |   |
|                                                                        |       |                                |       |                                 |       |   |   |   |   |
| Distribution Amount Per Unit (5,900,000 units  authorized and outstanding)  |       | $                                   | 1.6574     |                                 | $          | 1.4034 |   | $ | 0.6440 |   | $ | 0.4829 |   |

 

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

 

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**EASTERN AMERICAN NATURAL GAS TRUST**

 

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

 
| ** **                                                       | ** **   | **September 30, 2005** | ** **   | **December 31, 2004** | ** **   |
|------------------------------------------------------------------|--------------|------------------------|--------------|-----------------------|--------------|
| *** ***                                                     | *** *** | **(Unaudited)**        | *** *** | *** ***          | *** *** |
|                                                             |         |                   |         |                  |         |
| Assets:                                                          |         |                   |         |                  |         |
|                                                             |         |                   |         |                  |         |
| Cash                                                             |         | $                      | 259,221      |                  | $            | 185,752 |   |
| Net Proceeds Receivable                                          |         | 4,205,114              |         | 3,989,827             |         |
| Net Profits Interests in Gas Properties                          |         | 93,162,180             |         | 93,162,180            |         |
| Accumulated Amortization                                         |         | (64,861,764            | )            | (62,337,672           | )            |
|                                                             |         |                   |         |                  |         |
| Total Assets                                                     |         | $                      | 32,764,751   |                  | $            | 35,000,087 |   |
|                                                             |         |                   |         |                  |         |
| Liabilities  and Trust Corpus:                                   |         |                   |         |                  |         |
|                                                             |         |                   |         |                  |         |
| Trust General and Administrative                                 |         |                   |         |                  |         |
| Expenses Payable                                                 |         | $                      | 164,561      |                  | $            | 220,596 |   |
| Distributions Payable                                            |         | 3,799,774              |         | 3,639,983             |         |
| Trust Corpus (5,900,000 Trust Units authorized  and outstanding) |         | 28,800,416             |         | 31,139,508            |         |
|                                                             |         |                   |         |                  |         |
| Total Liabilities and Trust Corpus                               |         | $                      | 32,764,751   |                  | $            | 35,000,087 |   |

 

**The accompanying notes are an integral part of these condensedfinancial statements.**

 

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**EASTERN AMERICAN NATURAL GAS TRUST**

 

**STATEMENTS OF CHANGES IN TRUST CORPUS**

*(Unaudited)*

 
| ** **                                               | ** ** | **Nine Months  Ended  September 30, 2005** | ** ** | **Nine Months  Ended  September 30 2004** | ** ** |
|----------------------------------------------------------|------------|--------------------------------------------|------------|-------------------------------------------|------------|
|                                                     |       |                                       |       |                                      |       |
| Trust  Corpus, Beginning of Period                       |       | $                                          | 31,139,508 |                                      | $          | 34,857,666 |   |
| Distributable  Income                                    |       | 9,963,937                                  |       | 8,379,863                                 |       |
| Distributions  Payable to Unitholders                    |       | (9,778,937                                 | )          | (8,279,863                                | )          |
| Amortization  of Net Profits Interests in Gas Properties |       | (2,524,092                                 | )          | (2,785,090                                | )          |
|                                                     |       |                                       |       |                                      |       |
| Trust  Corpus, End of Period                             |       | $                                          | 28,800,416 |                                      | $          | 32,172,576 |   |

 

**The accompanying notes are an integral part of these condensedfinancial statements.**

 

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**EASTERN AMERICAN NATURAL GAS TRUST**

 

**NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS**

 

NOTE1.  Organization of the Trust

 

The Eastern American Natural Gas Trust (the “Trust”) was formed underthe Delaware Business Trust Act pursuant to a Trust Agreement (the “TrustAgreement”) among Eastern American Energy Corporation (“Eastern American”), asgrantor, Bank of Montreal Trust Company, as trustee, and Wilmington TrustCompany, as Delaware Trustee (the “Delaware Trustee”).  Effective May 8, 2000, The Bank of New Yorkacquired the corporate trust business of the then current Trustee and served asTrustee through December 31, 2004.   OnNovember 20, 2004, the holders of a majority of the Trust Units voting at aspecial meeting approved the resignation of The Bank of New York, as trusteeand depository of the Trust, and the appointment of JPMorgan Chase Bank, N.A.as successor trustee (“Trustee”) of the Trust. The appointment of JPMorgan Chase Bank, N.A., as successor trustee,became effective as of January 1, 2005. Effective January 1, 2005, the transfer agent for the Trust isBondholder Communications.

 

The Trust was formed to acquire and hold net profits interests (the “NetProfits Interests”) created from the working interests owned by EasternAmerican in 650 producing gas wells and 65 proved development well locations(the “Development Wells”) in West Virginia and Pennsylvania (the “UnderlyingProperties”).

 

On March 15, 1993, 5,900,000 Depositary Units were issued in a publicoffering at an initial public offering price of $20.50 per DepositaryUnit.  Each Depositary Unit consists ofbeneficial ownership of one unit of beneficial interest (“Trust Unit”) in theTrust and a $20 face amount beneficial ownership interest in a $1,000 faceamount zero coupon United States Treasury Obligation (“Treasury Obligation”)maturing on May 15, 2013.  The financialstatements of the Trust to which these notes relate do not include informationconcerning the Treasury Obligations, the beneficial interest in which is heldfor the Unitholders by the Depositary.

 

The Net Profits Interests are passive in nature, and neither theTrustee nor the Delaware Trustee has management control or authority over, norany responsibility relating to, the operation of the properties subject to theNet Profits Interests.  The TrustAgreement provides, among other things, that the Trust shall not engage in anybusiness or commercial activity or acquire any asset other than the Net ProfitsInterests initially conveyed to the Trust; the Trustee may establish a reservefor payment of any liability that is contingent, uncertain in amount or is notcurrently due and payable; the Trustee is authorized to borrow funds requiredto pay liabilities of the Trust, provided that such borrowings are repaid infull prior to further distributions to Unitholders; and the Trustee will makequarterly cash distributions to Unitholders from funds of the Trust.

 

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After the Trust was formed, 59 of the 65Development Wells were drilled and completed. The remaining six DevelopmentWells were not drilled. Clear title to two of the Development Wells could notbe established, and they were excluded from the Trust in accordance with theconveyance transferring them to the Trust. Eastern American asserted theremaining four undrilled Development Wells, if drilled, would be too close tothen existing wells on the property or an adjoining property, and thereaftersettled its dispute with the Trust about drilling those four Development Wellsby agreeinginstead to pay the Trust annually for the annual volume of gas projected to beproduced from those Development Wells as if they had been drilled.

 

The NetProfits Interests initially consisted of a royalty interest (“Royalty NPI”) in322 wells and a term interest (“Term NPI”) in the remaining wells andlocations. As of September 30, 2005, the Trust held Net Profits Interests in671 wells, consisting of Royalty NPI in 317 wells and Term NPI in the remainingwells. The Term NPI expire by their terms on May 15, 2013, or such earlier timeas 41,683 MMcf of gas has been produced that is attributable to EasternAmerican’s net revenue interest in the properties burdened by the Term NPI. Asof December 31, 2004, based on the Independent Petroleum Engineer’s Report,20,706 MMcf of the maximum 41,683 MMcf has been produced.

 

Between May15, 2012 and May 15, 2013 (the “Liquidation Date”), the Trustee is required tosell all the Royalty NPI and liquidate the Trust. Under the Trust Agreement,Eastern American has the right of first refusal to purchase any of the RoyaltyNPI the Trustee is required to sell after the Liquidation Date. If it exercisesthis right, Eastern American must pay the appraised Fair Value (as defined inthe Trust Agreement) of the Royalty NPI, or the relevant third party offerprice if a third party has offered to purchase the Royalty NPI. Unitholders ofrecord on the relevant record dates will receive the net proceeds from sellingthe Royalty NPI in accordance with the Trust Agreement, and also will receivetheir respective share of the matured face amount of the Treasury Obligationsheld by the Depositary.

 

NOTE2.  Basis of Presentation

 

The preparation of financial statements requires estimates andassumptions that affect reported amounts of assets and liabilities anddisclosure of contingent assets and liabilities at the date of the financialstatements and the reported amounts of revenue and expenses during thereporting period.  Without limiting theforegoing statement, the information furnished is based upon certain estimatesof production for the periods presented and is therefore subject to adjustmentin future periods to reflect actual production for the periods presented.  The information furnished reflects alladjustments which are, in the opinion of the Trustee, necessary for a fairpresentation of the results for the interim periods presented.  The accompanying financial statements areunaudited interim financial statements, and should be read in conjunction withthe audited financial statements and notes thereto included in the Trust’sAnnual Report on Form 10-K for the year ended December 31, 2004, as amended.

 

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NOTE3.  Trust Accounting Policies

 

The Trust serves as a pass-through entity, with items of depletion,interest income and expense, and income tax attributes being based upon thestatus and elections of Unitholders.  Thus,the Statements of Distributable Income show Distributable Income, defined asTrust income available for distribution to Unitholders, subject to CashReserves, if any, described in Part I, Item 2 before application of thoseUnitholders’ additional expenses, if any, for depletion, interest expense, andincome taxes.  The Trust uses the accrualbasis to recognize revenue, with Royalty Income recognized as gas reserves areextracted from properties and sold. Expenses are also presented on an accrual basis.  Actual cash receipts will vary from theaccrual of revenues due to, among other reasons, the payment provisions of thegas purchase contract between the Trust and Eastern Marketing Corporation  (a subsidiary of Eastern American), whichrequires payment with respect to gas production for a calendar quarter to bemade to the Trust on or before the tenth day of the third month following suchquarter.

 

The Net Profits Interests are assessed annually to determine whethertheir net capitalized cost is impaired. The Trust will determine if a writedown is necessary to its investmentin the Net Profits Interests in gas properties to the extent that totalcapitalized costs, less accumulated amortization, exceed undiscounted futurenet revenues attributable to proved gas reserves of the UnderlyingProperties.  The Trust will then providea writedown to the extent that the net capitalized costs exceed the discountedfuture net revenues attributable to proved gas reserves of the UnderlyingProperties.  Any such writedown would notreduce distributable income, although it would reduce Trust Corpus.

 

Amortization of the Net Profits Interests in Gas Properties iscalculated on a units-of-production basis, whereby the Trust’s cost basis inthe properties is divided by total Trust proved reserves to derive anamortization rate per reserve unit.  Suchamortization does not reduce distributable income, rather it is chargeddirectly to Trust Corpus.

 

The financial statements of the Trust differ from financial statementsprepared in accordance with accounting principles generally accepted in theUnited States of America due to the following: (i) certain cash reserves may beestablished for contingencies which were not accrued in the financialstatements; (ii) amortization of the Net Profits Interests in gas properties ischarged directly to Trust Corpus; and (iii) the sale of the Net ProfitsInterests is reflected in the Statements of Distributable Income as cashproceeds to the Trust.

 

NOTE4.  Income Taxes

 

The Trust is a grantor trust and is not required to pay federal orstate income taxes.  Accordingly, noprovision for federal or state income taxes has been made.  All income is taxed to the Unitholders of theTrust.

 

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ITEM2.  Management’s Discussion and Analysisof Financial Condition and Results of Operations

** **

**CautionaryStatement**

 

This Form 10-Q includes “forward-looking statements” within the meaningof Section 27A of the Securities Act of 1933, as amended, and Section 21E ofthe Securities Exchange Act of 1934, as amended. All statements other thanstatements of historical facts included in this Form 10-Q, including withoutlimitation the statements under “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations” are forward-looking statements.Although Eastern American has advised the Trustee that its believes that theexpectations reflected in the forward-looking statements contained herein arereasonable, no assurance can be given that such expectations will prove to havebeen correct. Important factors that could cause actual results to differmaterially from expectations (“Cautionary Statements”) are disclosed in thisForm 10-Q and in the Trust’s Annual Report on Form 10-K for the year endedDecember 31, 2004, as amended, and include the fact that none of the Trust, theTrustee or Eastern American is able to predict future changes in gas prices,gas production levels, economic activity, legislation or regulation, or certainchanges in expenses of the Trust. All subsequent written and oralforward-looking statements attributable to the Trust or persons acting on itsbehalf are expressly qualified in their entirety by the CautionaryStatements.  The Trust, the Trustee andEastern American disclaim any obligation to update any forward lookingstatements.

 

**General**

 

The Trust does not conduct any operations or activities.  The Trust’s purpose is, in general, to holdthe Net Profits Interests, to distribute the cash proceeds to Unitholders whichthe Trust receives in respect of the Net Profits Interests (net of Trustexpenses), and to perform certain administrative functions in respect of theNet Profits Interests and the Depositary Units. Accordingly, the Trust derives substantially all of its income and cashflows from the Net Profits Interests. The Trust has no source of liquidity or capital resources other than thecash flows from the Net Profits Interests.

 

The Net Profits Interests were created pursuant to conveyances (the “Conveyances”)from Eastern American to the Trust.  Inconnection therewith, Eastern American assigned its rights under a gas purchasecontract (the “Gas Purchase Contract”), which obligates Eastern MarketingCorporation, a subsidiary of Eastern American, to purchase all of the naturalgas produced from the Underlying Properties that is attributable to the NetProfits Interests.

 

TheConveyances and the Gas Purchase Contract entitle the Trust to receive anamount of cash for each calendar quarter equal to the Net Proceeds for suchquarter.  “Net Proceeds” for any calendarquarter generally means an amount of cash equal to (a) 90% of a volume of gasequal to (i) the volume of gas produced during such quarter attributable to theUnderlying Properties less (ii) a volume of gas equal to “Chargeable Costs” forsuch quarter, multiplied by (b) the applicable price for such quarter under theGas Purchase Contract.  “Chargeable Costs”is that 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”.

 

The“Operating Cost Charge” for 2005 is based on an annual rate of $535,224, andfor 2004 was an annual rate of $521,340. As provided in the Conveyances, the Operating Cost Charge will fluctuatebased 

 

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on the lesser of (A) fivepercent (5%) or (B) a percentage, not less than zero percent (0%), equal to thepercentage increase, if any, in the average weekly earnings of Crude Petroleumand Gas Production Workers for the last calendar year, as shown by the index ofaverage weekly earnings of Crude Petroleum and Gas Production Workers, aspublished by the United States Department of Labor, Bureau of Labor Statistics,based on December-to-December comparison.

 

During 2003, the United States Department of Labor, Bureau of LaborStatistics converted all of its industry-based statistics to a differentreporting system that was developed in cooperation with the United States’North American Free Trade Agreement Partners, Canada and Mexico, in an effortto standardize and modernize reporting codes. As a result of this conversion, the Crude Petroleum and Gas ProductionWorkers index is no longer available for use in the annual calculation ofoverhead adjustment called for in the various Council of Petroleum AccountantsSocieties (“COPAS”) model forms after March 2003.

 

Researchby COPAS covering the past ten years indicated that by blending the Oil and GasExtraction Index with the Professional and Technical Services Index, theresults approximate the data from the old Crude Petroleum and Natural GasWorkers Index.  Accordingly, COPAS hascalculated the percentage change in the simple average of the Oil andExtraction Index and the Professional and Technical Services Index, commencingin April 2004.  This “Overhead AdjustmentIndex” has been provided as a guidance to the industry as a replacement indexfor use in calculating the overhead adjustment. The adjustment for the effective time period is 3.5%.  Since the Conveyance Documents do notspecifically provide for a replacement index if the Crude Petroleum and GasProduction Workers Index is no longer published, Eastern American believes, andadvised the Trustee, that the “Overhead Adjustment Index” as calculated byCOPAS is a reasonable index to utilize since the industry is generally adoptingthe same as a replacement.  EasternAmerican, with the concurrence of the Trustee, will utilize this “OverheadAdjustment Index” to adjust the “Operating Cost Charge” so long as such indexis published by COPAS.

 

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

 

Pursuant to the Gas Purchase Contract, Eastern Marketing is obligatedto purchase such gas production at a purchase price per Mcf equal to the IndexPrice.  The Index Price for any quarteris determined 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.  The Henry Hub Average Spot Price is definedas the price per MMBtu determined for any calendar quarter equal to the priceobtained with respect to each of the three months in such quarter, in themanner specified below, and then taking the average of the prices determinedfor each of such three months.  The pricedetermined for any month of such quarter is equal to the average of (i) the finalsettlement price per MMBtu for Henry Hub Gas Futures Contracts (as defined), asreported in *The Wall Street Journal*, for suchcontracts which expired in each of the five months prior to such month; (ii)the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, asreported in *The Wall Street Journal*, for suchcontracts which expire during such month; and (iii) the closing settlementprice per MMBtu of Henry Hub Gas Futures Contracts determined as of the 

 

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contractsettlement date for such month, as reported in *The WallStreet Journal*, for such contracts which expire in each of the sixmonths following such month.  A Henry HubGas Futures Contract is defined as a gas futures contract for gas to bedelivered to the Henry Hub that is traded on the New York Mercantile Exchange.

 

Accordingly, the Index Price payable to the Trust for production may behigher or lower based on the fluctuations in natural gas futures prices duringthe relevant calculation period.  Theprice payable to the Trust will have a direct impact, positively or negatively,on the quarterly distributions payable by the Trust to its unit holders.

 

EasternAmerican had a disagreement with the Trust over Eastern American’s obligationto drill certain Development Wells that were closely offset by thirdparties.  The Trust agreed that in lieuof drilling these closely offset Development Wells, Eastern American couldprovide the Trust, on an annual basis commencing on April 1, 1997, and over theremaining life of the Trust, a volume of gas which is equal to the projectedvolumes of the wells as if they had been drilled.  These volumes have been estimated by RyderScott Company, independent petroleum engineers. During the quarter ended September 30, 2005, an additional volume of4,123 Mcf was delivered to the Trust, as compared to 4,457 Mcf for the quarterended September 30, 2004.  Theseadditional volumes fulfill Eastern American’s obligation to provide volumes forDevelopment Wells that had been closely offset by third parties.

 

Eastern American has fulfilled its obligation with respect to thedrilling of the Development Wells. Since the inception of the Trust, Easternhas drilled a total of 59 Development Wells, which are online andproducing.  (See the Trust’s AnnualReport on Form 10-K for the fiscal year ended December 31, 2004, as amended,for a more complete description of the Development Wells.)

 

During 2004, an oil and gas company contacted Eastern American andinquired as to whether it would sell certain assets situated in Centre County,Pennsylvania including the Horne #1, Horne #2 and Horne #15 wells (“the HorneUnderlying Properties”), which are wells in which the Trust owns a Net ProfitsInterests.  Eastern American reviewed theTrust Agreement and certified to the Trustee that:  (i) the gross purchase price to be receivedby Eastern American for the sale of the Horne Underlying Properties in a singletransaction or a series of related transactions is less than $500,000; (ii) theAssignee of the Horne Underlying Properties is not an Affiliate of EasternAmerican; (iii) the aggregate sale proceeds of $80,205 to be received by theTrust from Eastern American (the Trust’s Horne Sale Proceeds) represents thefair value to the Trust for Net Profits Interests to be released by the Trusteein connection with Eastern American’s sale of the Horne Underlying Properties;and (iv) the Trust’s Horne Sale Proceeds plus the aggregate sale proceedsreceived by the Trust pursuant to Section 3.02(b)(ii) of the Trust Agreementwith respect to all other Net Profits Interests previously released by theTrustee pursuant to Section 3.02(b) during the most recently completed twelvecalendar months did not exceed $500,000. Eastern American advised the oil and gas company that it could sellthese wells.  The effective date of thesale was May 1, 2004.  The Trust’s shareof the proceeds of $80,205 was included in the Distributable Income of theTrust during the quarter ended June 30, 2004.

 

Also, during 2004, a landowner contacted Eastern American to inquireabout the sale of certain wells located on the landowner’s property, includingthe Wurst #2 well, which is a well in which the Trust owns a Net ProfitsInterest.  Eastern certified to the Trustthat: (i) the Assignee of the Wurst #2 was not an Affiliate of Eastern and;(ii) the aggregate sale proceeds to be received from all other sales of wellsin 

 

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whichthe Trust owns a Net Profits Interest and previously released by the Trustduring the preceeding twelve (12) calendar months did not exceed $500,000.  The Wurst #2 well was found to be uneconomicto operate and was subject to plugging and abandonment by Eastern American ifnot assigned to the landowner.  EasternAmerican advised the landowner that it could assign this well. The Wurst #2well had no value and no cash distribution was made to the Trust.

 

Over the remaining life of the Trust, additional wells may be disposedof for similar or other reasons.

 

During the quarter ended September 30, 2005, the Trust incurredsubstantially increased fees for professional services relating to thepotential exchange offer described below under “Other Information”.  These expenses, and any related expenses,will decrease distributions to the Unitholders. Expenses relating to the potential exchange offer actually incurred bythe Trust during the quarter ended September 30, 2005 include a $100,000 feepaid to the independent financial advisor retained by the Trust to assist withan evaluation of the potential exchange offer, and approximately $50,000 inadditional legal fees relating to the potential exchange offer.  The terms of the engagement agreement withthe financial advisor would require the Trust to pay the financial advisor (i)an additional $150,000 if the Trust requests that a description of thefinancial advisor’s analysis of the exchange offer be included in any filingsor materials to be delivered to the Unitholders, or (ii) an additional $300,000if the Trust requests a written opinion from the financial advisor as towhether the offer (if made) is fair, from a financial point of view, to theUnitholders.  In addition, the Trust hasincurred and is likely to continue to incur increased legal and other expensesrelating to the potential exchange offer. Further, the Trust has incurred an additional expense of approximately$13,200 payable to the Trust’s independent petroleum engineers for the updatedreserve report described below under “Other Information” and filed herewith asAnnex A.  The aggregate amount of futureadditional expenses may be substantially greater.

 

**CriticalAccounting Policies**

 

The following is a summary of the critical accounting policies followedby the Trust.

 

*Basis of Accounting:*

 

The financial statements of the Trust differ from financial statementsprepared in accordance with accounting principles generally accepted in theUnited States of America due to the following: (i) certain cash reserves may beestablished for contingencies which were not accrued in the financialstatements; (ii) amortization of the Net Profits Interests in gas properties ischarged directly to Trust Corpus; and (iii) the sale of the Net ProfitsInterests is reflected in the Statements of Distributable Income as cashproceeds to the Trust.

 

*Net Profits Interests inGas Properties:*

 

The Net Profits Interests in gas properties are periodically assessedto determine whether their net capitalized cost is impaired.  The Trust will determine if a writedown isnecessary to its investment in the Net Profits Interests in gas properties tothe extent that total capitalized costs, less accumulated amortization, exceedundiscounted future net revenues attributable to proved gas reserves of theUnderlying Properties.  The Trust willthen provide a writedown to the extent that the net capitalized costs exceedthe discounted future net revenues attributable to proved gas reserves of theUnderlying 

 

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Properties.  Any such writedown would not reducedistributable income, although it would reduce Trust Corpus.

 

Amortization of the Net Profits Interests in gas properties iscalculated on a units-of-production basis, whereby the Trust’s cost basis inthe properties is divided by total Trust proved reserves to derive anamortization rate per reserve unit.  Suchamortization does not reduce distributable income, rather it is chargeddirectly to Trust Corpus.  Revisions toestimated future units-of-production are treated on a prospective basisbeginning on the date significant revisions are known.

 

The Net Profits Interest impairment test and the determination ofamortization rates are dependent on estimates of proved gas reservesattributable to the Trust.  Numerousuncertainties are inherent in estimating reserve volumes and values, includingeconomic and operating conditions, and such estimates are subject to change asadditional information becomes available.

 

**Liquidityand Capital Resources**

 

The Trust has no source of liquidity or capital resources other thanthe distributions received from the Net Profits Interests.

 

 In accordance with the provisions of theConveyances, generally all revenues received by the Trust, net of Trustadministrative and operating expenses and the amount of established reserves,are distributed currently to the Unitholders.

 

TheTrust did not have any contractual obligations as of September 30, 2005.  At September 30, 2005, the Trust had accountspayable of $164,561 and distributions payable of $3,799,774.

 

Comparisonof Results of Operations for Three Months Ended September 30, 2005 and ThreeMonths Ended September 30, 2004

 

The Trust’s distributable income was $3,799,774 for the three monthsended September 30, 2005 as compared to $2,849,395 for the three months endedSeptember 30, 2004.  This increase wasdue to an increase in Royalty Income for the three months ended September 30,2005 to $4,659,185 as compared to the three months ended September 30, 2004 of$3,452,442.  The increase in RoyaltyIncome was due to an increase in the price payable to the Trust under the GasPurchase Contract as discussed below ($9.268 per Mcf for the three months endedSeptember 30, 2005; $7.106 per Mcf for the three months ended September 30,2004).  This increase was also due to anincrease in production of gas attributable to the Net Profits Interests for thethree months ended September 30, 2005 (504 Mmcf) as compared to the threemonths ended September 30, 2004 (485 Mmcf). The increase in production is primarily attributable to shut-ins duringthe quarter ended September 30, 2004. Taxes on production and property were $320,484 for the three monthsended September 30, 2005 as compared to $232,004 for the three months endedSeptember 30, 2004. The increase in taxes is due directly to the increase inRoyalty Income as discussed above.  Trustgeneral and administrative expenses were $405,340 for the three months endedSeptember 30, 2005 as compared to $242,168 for the three months ended September30, 2004.  This increase in general andadministrative expense of $163,172 was primarily related to an increase inprofessional service fees for costs associated with services provided to theTrustee relating to the potential exchange offer described below under “OtherInformation”.

 

12

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The price payable to the Trust for gas production attributable to theNet Profits Interests was $9.268 per Mcf for the three months ended September30, 2005 and $7.106 per Mcf for the three months ended September 30, 2004.  The price per Mcf was higher for the threemonths ended September 30, 2005 than for the corresponding three month periodended September 30, 2004 due to an increase in the average spot market pricefor gas delivered at the Henry Hub near Henry, Louisiana ($8.125 per Dth forthe three months ended September 30, 2005; $6.160 per Dth for the three monthsended September 30, 2004).

 

Comparisonof Results of Operations for Nine Months Ended September 30, 2005 and NineMonths Ended September 30, 2004

 

The Trust’s distributable income was $9,963,937 for the nine monthsended September 30, 2005 as compared to $8,379,863 for the nine months endedSeptember 30, 2004.   This increase wasdue to an increase in Royalty Income for the nine months ended September 30,2005 to $12,221,141 as compared to $10,024,331 for the nine months endedSeptember 30, 2004.  The increase inRoyalty Income was due to an increase in the average price payable to the Trustunder the Gas Purchase Contract as discussed below ($8.221 per Mcf for the ninemonths ended September 30, 2005; $6.645 per Mcf for the nine months endedSeptember 30, 2004).  This increase wasoffset by a decrease in production of gas attributable to the Net ProfitsInterests for the nine months ended September 30, 2005 (1,487 Mmcf) as comparedto the nine months ended September 30, 2004 (1,508 Mmcf).  The decline in production is primarilyattributable to natural production declines and the sale of wells.  Taxes on production and property were$839,691 for the nine months ended September 30, 2005 as compared to $683,658for the nine months ended September 30, 2004. The increase in taxes is due directly to the increase in Royalty Incomeas discussed above.  Trust general andadministrative expenses were $1,017,252 for the nine months ended September 30,2005 as compared to $651,903 for the nine months ended September 30, 2004.  This increase in general and administrativeexpense of $365,349 was primarily related to an increase in professionalservice fees for costs associated with the procedures required by the  Sarbanes-Oxley Act of 2002 and costsassociated with services provided to the Trustee relating to the potentialexchange offer described below under “Other Information”.  During the nine months ended September 30,2005, the Trustee added $185,000 to the reserve as compared to $100,000 for thenine months ended September 30, 2004. The Trustee established this reserve amount to facilitate the payment ofvendor invoices on a timely basis.  Thedistributable income includes no Cash Proceeds on Sale of Net Profits Interestsfor the nine months ended September 30, 2005, while $80,205 was recognized inthe corresponding nine months of the prior year.  Amortization of Net Profits Interests in GasProperties was $2,524,092 for the nine months ended September 30, 2005 ascompared to $2,785,090 for the nine months ended September 30, 2004.  This decrease was primarily due to thedecrease in production volumes.

 

The average price payable to the Trust for gas production attributableto the Net Profits Interests was $8.221 per Mcf for the nine months endedSeptember 30, 2005 and $6.645 per Mcf for the nine months ended September 30,2004.  The price per Mcf was higher forthe nine months ended September 30, 2005 than for the corresponding nine monthperiod ended September 30, 2004 due to an increase in the average spot marketprice for gas delivered at the Henry Hub near Henry, Louisiana ($7.173 per Dthfor the nine months ended September 30, 2005; $5.741 per Dth for the ninemonths ended September 30, 2004).

 

13

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**Off-BalanceSheet Arrangements**

 

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

 

**OtherInformation**

 

*UnitedStates Treasury Obligations*

 

For the calendar quarter ended September 30, 2005, the high and lowclosing prices of the Treasury Obligations (which have $1,000 face principalamount), as quoted in the over-the-counter market for United States Treasuryobligations were $734.41 and $708.72, respectively.  On September 30, 2005, the closing price ofthe Treasury Obligations, as quoted on such market, was $720.34.

 

The Trust provides Unitholders with the option to separate the relatedTreasury Obligation from the Trust Units. Upon exercising this option, the Trustee transfers such Trust Units fromthe name of the Depositary to the name of the withdrawing Unitholder.  As of September 30, 2005, this option wasexercised on 19,900 Trust Units.  (Seethe Trust’s 10-K for the fiscal year ended December 31, 2004 for a morecomplete description of the Withdrawal of Trust Units and Restriction onTransfer.)

 

*Ensource Energy Income Fund LP*

 

The Trustee is aware that Ensource Energy Income Fund LP, a recentlyformed Delaware limited partnership not affiliated with the Trust (“Ensource”),has filed a Registration Statement on Form S-4 with the Securities and ExchangeCommission.  The filing describes aproposed transaction pursuant to which Ensource would attempt to acquirecontrol of, and ultimately the entire interest in, the Trust.

 

The Trustee cannot predict whether Ensource will proceed with theproposed transaction or, if it does proceed, whether Ensource will be able toacquire a majority of the outstanding Trust units or, if it does acquire amajority of the outstanding units, whether it will proceed with or be able toconsummate the second-step merger described in the Form S-4.

 

If Ensource proceeds with the proposed transaction on the termsdescribed in the Form S-4, the Trust will be required by rules of the SEC tomake a recommendation whether Unitholders should accept or reject the exchangeoffer or to state that the Trust is remaining neutral with respect to theexchange offer.  The Trust has retained afinancial advisor to assist the Trust with an evaluation of any such exchangeoffer.  The Trust has also received aletter from the operator of the underlying properties and original sponsor ofthe Trust, Eastern American, stating that Eastern American’s initial review ofthe Form S-4 leads Eastern American to believe that the Ensource proposalsubstantially changes the original structure and business risk exposure of theTrust and exposes the Unitholders to the vagaries of the oil and gas business,and as such, may not be in the best interest of the Unitholders.  In the letter, Eastern American made a numberof specific comments regarding the proposed 

 

14

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exchangeoffer and noted that it has yet to form an opinion as to which, if any, of theunderlying documents may or may not continue in effect subsequent to theproposed exchange.

 

*Updated Reserves Report*

 

*Introduction.*  The Trust normally obtains a report of oiland gas reserves attributable to the Trust as of the end of the calendar yearprepared by Ryder Scott Company, which is an independent petroleum engineeringfirm, and the Trust normally includes a copy of that annual report in itsAnnual Report on Form 10-K.  In light ofthe potential exchange offer that Ensource may make to the Unitholders asdescribed briefly above, the Trust determined that it would be prudent and inthe best interests of the Unitholders to obtain an updated reserve report sothat Unitholders would have the benefit of a relatively current report in theevent that Ensource proceeds with its proposed exchange offer.  The Trust therefore engaged Ryder ScottCompany to prepare an updated report as of September 1, 2005, a copy of whichis included as Annex A to this Form 10-Q. The information in the report is subject to the same limitations andqualifications as are applicable to prior reports prepared by Ryder ScottCompany, as described in the report and in the Trust’s Annual Report on Form10-K for the year ended December 31, 2004. Following is a summary of the information contained in the updatedreserve report.

 

*Proved Reserves of Underlying Properties andNet Profits Interests.*The following table sets forth,as of September 1, 2005, certain estimated proved reserves, estimated futurenet revenues and the discounted present value thereof attributable to theUnderlying Properties, the Royalty NPI and the Term NPI, in each case derivedfrom a report of oil and gas reserves attributable to the Trust as ofSeptember 1, 2005 prepared by Ryder Scott Company (the “Reserve Report”).Proved reserve quantities attributable to the Net Profits Interests arecalculated by subtracting an amount of gas sufficient, if sold at the pricesused in preparing the reserve estimates, to pay the future estimated costs andexpenses 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 productionbeyond the earlier of May 15, 2013 or such time as 41,683 MMcf of gas has beenproduced which is attributable to Eastern American’s net revenue interests inthe properties burdened by the Term NPI. The discounted present value ofestimated future net revenues was determined using a discount rate of 10% inaccordance with applicable requirements. A copy of the Reserve Report isincluded as Annex A hereto.

 

15

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| ** **               | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** | **Estimated  Future Net  Revenues(2)** | ** ** | **Discounted  Estimated  Future Net  Revenues(2)** | ** ** |
|--------------------------|------------|-----------------|------------|------------|------------|------------|------------|----------------------------------------|------------|----------------------------------------------------|------------|
| **Proved Gas Reserves**  |
| **(MMcf)**               |
| **Developed**            | ** ** | **Undeveloped** | ** ** | **Total**  |
| ** **               | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** | **(Dollars in thousands)**             | ** ** |
|                     |       |            |       |       |       |       |       |                                   |       |                                               |       |
| Underlying Properties(1) |       | 35,107          |       | 0          |       | 35,107     |       | $                                      | 278,698    |                                               | $          | 113,611 |   |
|                     |       |            |       |       |       |       |       |                                   |       |                                               |       |
| Net Profits Interests:   |       |            |       |       |       |       |       |                                   |       |                                               |       |
| Royalty NPI              |       | 11,052          |       | 0          |       | 11,052     |       | $                                      | 102,428    |                                               | $          | 43,327 |   |
| Term NPI                 |       | 6,272           |       | 0          |       | 6,272      |       | 58,128                                 |       | 41,833                                             |       |
|                     |       |            |       |       |       |       |       |                                   |       |                                               |       |
| Total                    |       | 17,324          |       | 0          |       | 17,324     |       | $                                      | 160,556    |                                               | $          | 85,160 |   |

 

----

(1)Reserve volumes and estimated future net revenues for UnderlyingProperties reflect volumes and revenues distributable to Eastern American’sentire net revenue interest with respect to the Underlying Properties.

 

(2)The effects of depreciation, depletion and federal income tax havenot been taken into account in estimating future net revenues. Estimated futurenet revenues and discounted estimated future net revenues are not intended, andshould not be interpreted, as representing the fair market value for theestimated reserves.

 

The value ofthe Depositary 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 and FinancialAccounting Standards Board for disclosure of reserves and should not beconsidered representative of the market value of such reserves or theDepositary Units or the Trust Units evidenced thereby. A market valuedetermination would include many additional factors.

 

The priceassumptions used by Ryder Scott Company in preparing the updated reserve reportwere furnished to Ryder Scott Company by Eastern American Energy Corporationand were prepared in accordance with applicable SEC guidelines and the terms ofthe Gas Purchase Contract between the Trust and Eastern MarketingCorporation.  The price under the GasPurchase Contract as of August 31, 2005 was $9.268 per Mcf and was based on theHenry Hub Average Spot Price (as defined in the Gas Purchase Contract) of$8.125 per Mmbtu.

 

If Ensourceproceeds with the proposed exchange offer, Unitholders will receive furtherinformation regarding the exchange offer and any recommendation the Trust maymake.

 

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

 

The Trust does not engage in any operations, and does not utilizemarket risk sensitive instruments, either for trading purposes or for otherthan trading purposes.  As describedelsewhere herein, the 

 

16

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DepositaryUnits consist of beneficial ownership of one unit of beneficial interest in theTrust and a $20 face amount beneficial ownership interest in a $1,000 faceamount zero coupon Treasury Obligation maturing on May 15, 2013.  High and low price information for theTreasury Obligations is included under Part II Item 5.  As described elsewhere herein, gas productionattributable to the Net Profits Interest is sold to a wholly owned subsidiaryof Eastern American pursuant to the Gas Purchase Contract described herein, andthe Trust’s quarterly distributions are highly dependent on the price payableto the Trust for gas production attributable to the Net Profits Interest.  Natural gas prices can fluctuate widely inresponse to many factors, all of which are out of the control of the Trust, theTrustee and Eastern American.

 

ITEM 4.  Controls and Procedures

 

*Evaluation of Disclosure Controls and Procedures. *The Trustee maintains disclosure controls and procedures designed toprovide reasonable assurance that information required to be disclosed by theTrust in the reports that it files or submits under the Securities Exchange Actof 1934, as amended, is recorded, processed, summarized and reported within thetime periods specified in the SEC’s rules and regulations.  Disclosure controls and procedures includecontrols and procedures designed to provide reasonable assurance thatinformation required to be disclosed by the Trust is accumulated andcommunicated by several parties, including without limitation, the working interestowner, Eastern American, and the independent reserve engineer to JPMorgan ChaseBank, N.A., as Trustee of the Trust, and its employees who participate in thepreparation of the Trust’s periodic reports as appropriate to allow timelydecisions regarding required disclosure. In addition, the Trustee is required by the Trust Agreement to engageand has engaged an independent registered public accounting firm to review thequarterly financial statements of the Trust and audit the annual financialstatements of the Trust, which includes financial data provided by EasternAmerican.

 

As of September 30, 2005,the Trustee carried out an evaluation of the Trustee’s disclosure controls andprocedures, as defined under Rules 13a-15(e) and 15d-15(e) under the SecuritiesExchange Act.  Mike Ulrich, a VicePresident of JPMorgan Chase Bank, N.A., has concluded that the controls and proceduresare effective at the reasonable assurance level, while noting certainlimitations on 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 to the extent considered reasonable on Eastern Americanto provide accurate and timely information 

 

17

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whenrequested for use in the Trust’s reports.

•                  Underthe terms of the Trust Agreement, the Trustee is entitled to, and in fact does,rely upon in good faith the independent reserve engineer, as an expert withrespect to the annual reserve report, which includes projected production,operating expenses and capital expenses. Other than reviewing the financial and other information provided to theTrust by Eastern American on a quarterly basis, the Trustee makes no independentor direct verification of this financial or other information. While theTrustee has no reason to believe its reliance upon this expert is unreasonable,this reliance on an expert and restricted access to information may be viewedas a weakness.

 

The Trustee does not intendto expand its responsibilities beyond those permitted or required by the TrustAgreement and those required under applicable law.

 

**Changes in Internal Control Over Financial Reporting**

 

There has been no change inthe Trustee’s internal control over financial reporting during the three monthsended September 30, 2005 that has materially affected, or is reasonably likelyto materially affect, the Trustee’s internal control over financialreporting.  The Trustee notes forpurposes of clarification that it has no authority over, and makes no statementconcerning, the internal control over financial reporting of Eastern American.

### ** **

**PART II – OTHER INFORMATION**

 

ITEM 1.       Legal Proceedings.

 

None.

 

ITEM 2.       Unregistered Sales of Equity Securitiesand Use of Proceeds.

 

None.

 

ITEM 3.       Defaults Upon Senior Securities.

 

None.

 

ITEM 4.       Submission of Matters to a Vote ofSecurity Holders.

 

None.

 

ITEM 5.       Other Information.

 

None.

 

ITEM 6.       Exhibits.

 

18

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| **Exhibit  Number** | ** ** | **Description**                                                                                                                                  |
|---------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------|
|                |       |                                                                                                                                             |
| 3.1*                |       | Second Amended and Restated Trust Agreement  of Eastern American Natural Gas Trust                                                               |
|                |       |                                                                                                                                             |
| 4.1*                |       | Specimen Depositary  Receipt                                                                                                                     |
|                |       |                                                                                                                                             |
| 4.2*                |       | Form of NPI Royalty  Deposit Agreement                                                                                                           |
|                |       |                                                                                                                                             |
| 10.1*               |       | Form of Conveyance                                                                                                                               |
|                |       |                                                                                                                                             |
| 10.2*               |       | Form of Term NPI  Conveyance                                                                                                                     |
|                |       |                                                                                                                                             |
| 10.3*               |       | Form of Gas Purchase  Contact between Eastern American Energy Corporation, Eastern Marketing  Corporation and Eastern American Natural Gas Trust |
|                |       |                                                                                                                                             |
| 10.5*               |       | Form of Conveyance of  Production Payment/Assignment of Production from Eastern American Natural Gas  Trust to Eastern Marketing Corporation     |
|                |       |                                                                                                                                             |
| 10.6*               |       | Form of Assignment and  Standby Performance Agreement                                                                                            |
|                |       |                                                                                                                                             |
| 23.1                |       | Consent of Ryder Scott  Company                                                                                                                  |
|                |       |                                                                                                                                             |
| 31.                 |       | Rule 13a-14(a)/15d-14(a)  Certification                                                                                                          |
|                |       |                                                                                                                                             |
| 32.                 |       | Section 1350 Certification                                                                                                                       |

 

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*    Incorporated by reference tothe indicated exhibits to filings previously made by the registrant with theSecurities and Exchange Commission.  Allreferences are to the registrant’s Registration Statement on Form S-1,Registration No. 33-56336, except for Exhibit 3.1, which is incorporated byreference to the Registrant’s Annual report on Form 10-K for the year endedDecember 31, 1994.

 

19

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|                              |   |   | DENVER,  COLORADO 80293 |   | TEL (303)  623-9147 |   | FAX (303)  623-4258 |
|------------------------------|--------|--------|-------------------------|--------|---------------------|--------|---------------------|
|                              |
| 621 17TH  STREET, SUITE 1550 |

 

 

October 13, 2005

 

 

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

Institutional Trust Services

700 Lavaca,  2nd Floor

Austin, Texas 78701

 

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 September 1, 2005.  The Trust is a grantor trust formed to holdinterests in certain domestic oil and gas properties owned by Eastern AmericanEnergy Corporation (EAEC), a wholly owned subsidiary of Energy Corporation ofAmerica (ECA).  The interests conveyed tothe Trust consist of a net profits interest derived from working and royaltyinterests in numerous properties.  TheNet Profits Interest consists of (1) a life-of-properties interest (“RoyaltyNPI”) and (2) a term interest (“Term NPI”). The properties included in the Trust are located in the states ofPennsylvania and West Virginia.

 

Theestimated reserve quantities and future income quantities presented in thisreport are related to a large extent to hydrocarbon prices.  Hydrocarbon prices in effect at August 31,2005 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 fromAugust 31, 2005 prices for reasons discussed in more detail in other sectionsof this report.  Therefore, quantities ofreserves actually recovered and quantities of income actually received maydiffer significantly from the estimated quantities presented in this report.

 

 

A-1

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| ** **            | ** ** | **As of September 1, 2005** | ** ** |
|-----------------------|------------|-----------------------------|------------|
| ** **            | ** ** | ** **                  | ** ** | **Estimated** | ** ** | **Present** | ** ** |
| ** **            | ** ** | ** **                  | ** ** | **Future Net** | ** ** | **Value** | ** ** |
| ** **            | ** ** | **Gas**                     | ** ** | **Cash Inflows** | ** ** | **At 10%** | ** ** |
| ** **            | ** ** | **(MMCF)**                  | ** ** | **(M$)** | ** ** | **(M$)** | ** ** |
| Proved Net  Developed |       |                        |       |   |   |   |   |
|                  |       |                        |       |   |   |   |   |
| Royalty NPI           |       | 11,052                      |       | 102,428 |   | 43,327 |   |
| Term NPI              |       | 6,272                       |       | 58,128 |   | 41,833 |   |
| Total                 |       | 17,324                      |       | 160,556 |   | 85,160 |   |

 

Reserve quantities are calculated differentlyfor a Net 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 September 1, 2005 for natural gas.  Accordingly, there is no precise method ofallocating estimates of the quantities of proved reserves attributable to theNet Profits Interest between the interest held by the Trust and the intereststo be retained by EAEC.  For purposes ofthis presentation, the proved reserves attributable to the Net ProfitsInterests have been proportionately reduced to reflect the future estimatedcosts and expenses deducted in the calculation of Net Proceeds with respect tothe Net Profits Interests.  Accordingly,the reserves presented for the Net Profits Interest reflect quantities of gasthat are free of future costs or expenses based on the price and costassumptions utilized in this report.  Theallocation of proved reserves of the Net Profits Interest between the Trust andEAEC will vary in the future as relative estimates of future gross revenues andfuture net incomes vary.  Furthermore,EAEC requested that for purposes of our report the “Royalty NPI” be calculatedbeyond the Liquidation Date of May 15, 2013, even though by the terms of theTrust Agreement the Royalty NPI will be sold by the Trustee on or about thisdate and a liquidating distribution of the sales proceeds from such sale wouldbe made to holders of Trust Units.  TheTrust Agreement provides that the “Term NPI” entitles the Trust to receive thenet proceeds from the gas produced from the properties burdened by the “TermNPI” until the earlier of May 15, 2013 or until such time as 41,683 MMCF of gashas been produced.  For purposes of thisreport, the “Term NPI” was limited to May 15, 2013.

 

All gas volumes are sales gas expressed inMMCF at the pressure and temperature bases of the area where the gas reservesare located.  The estimated future netcash inflows are described later in this report.

 

The proved reserves presented in this reportcomply with the Securities and Exchange Commission’s Regulation S-X Part210.4-10 Sec. (a) as clarified by subsequent Commission Staff AccountingBulletins, and are based on the following definitions and criteria:

 

Proved reserves ofcrude 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, 

 

 

A-2

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proved reserves may be assigned on the basis of a combination of coreanalysis and electrical and other type logs which indicate the reservoirs areanalogous to reservoirs in the same field which are producing or havedemonstrated the ability to produce on a formation test.  The area of a reservoir considered provedincludes (1) that portion delineated by drilling and defined by fluid contacts,if any, and (2) the adjoining portions not yet drilled that can be reasonablyjudged as economically productive on the basis of available geological andengineering data.  In the absence of dataon fluid contacts, the lowest known structural occurrence of hydrocarbonscontrols the lower proved limit of the reservoir.  Proved reserves are estimates of hydrocarbonsto be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional databecomes available. Proved natural gas reserves consist of non-associated,associated and dissolved gas.  Anappropriate reduction in gas reserves has been made for the expected removal ofnatural gas liquids, for lease and plant fuel, and for the exclusion of non-hydrocarbongases if they occur in significant quantities.

 

Reserves that can be produced economicallythrough the application of improved recovery techniques are included in theproved classification when these qualifications are met:  (1) successful testing by a pilot project orthe operation of an installed program in the reservoir provides support for theengineering analysis on which the project or program was based, and (2) it isreasonably certain the project will proceed. Improved recovery includes all methods for supplementing naturalreservoir forces and energy, or otherwise increasing ultimate recovery from areservoir, including (1) pressure maintenance, (2) cycling, and (3) secondaryrecovery in its original sense.  Improvedrecovery also includes the enhanced recovery methods of thermal, chemicalflooding, and the use of miscible and immiscible displacement fluids.

 

Estimates of proved reserves do not includecrude oil, natural gas, or natural gas liquids being held in underground orsurface storage.

 

(i) “developed reserves” which are thoseproved reserves reasonably expected to be recovered through existing wells withexisting equipment and operating methods, including (a) “developed producingreserves” which are those proved developed reserves reasonably expected to beproduced from existing completion intervals now open for production in existingwells, and (b) “developed non-producing reserves” which are those proveddeveloped reserves which exist behind the casing of existing wells which arereasonably expected to be produced through these wells in the predictablefuture where the cost of making such hydrocarbons available for productionshould be relatively small compared to the cost of a new well; and

 

(ii) “undeveloped reserves” which are thoseproved reserves reasonably expected to be recovered from new wells on undrilledacreage, from existing wells where a relatively large expenditure is requiredand from acreage for which an application of fluid injection or other improvedrecovery technique is contemplated where the technique has been provedeffective by actual tests in the area in the same reservoir.  Reserves from undrilled acreage are limitedto those 

 

 

A-3

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drilling units offsetting productive unitsthat are reasonably certain of production when drilled.  Proved reserves for other undrilled units areincluded only where it can be demonstrated with reasonable certainty that thereis continuity of production from the existing productive formation.

 

In accordance with the requirements of FASB69, estimates of future cash inflows, future costs and future net cash inflowsbefore income tax, as well as estimated reserve quantities, as of September 1,2005 from this report are presented in the following table:

 
| ** **                                       | ** ** | **As of September 1, 2005** | ** ** |
|--------------------------------------------------|------------|-----------------------------|------------|
| ** **                                       | ** ** | **Royalty**                 | ** ** | **Term** | ** ** | ** ** | ** ** |
| ** **                                       | ** ** | **NPI**                     | ** ** | **NPI** | ** ** | **Totals** | ** ** |
| Total Proved                                     |       |                        |       |   |   |   |   |
| Future Cash Inflows (M$)                         |       | 102,428                     |       | 58,128 |   | 160,556 |   |
| Future Costs                                     |       |                        |       |   |   |   |   |
| Production (M$)                                  |       | 0                           |       | 0 |   | 0 |   |
| Development (M$)                                 |       | 0                           |       | 0 |   | 0 |   |
| Total Costs (M$)                                 |       | 0                           |       | 0 |   | 0 |   |
|                                             |       |                        |       |   |   |   |   |
| Future Net Cash Inflows   Before Income Tax (M$) |       | 102,428                     |       | 58,128 |   | 160,556 |   |
|                                             |       |                        |       |   |   |   |   |
| Present Value at 10%   Before Income Tax (M$)    |       | 43,327                      |       | 41,833 |   | 85,160 |   |
|                                             |       |                        |       |   |   |   |   |
| ** **                                       | ** ** | **As of September 1, 2005** | ** ** |
| ** **                                       | ** ** | **Royalty**                 | ** ** | **Term** | ** ** | ** ** | ** ** |
| ** **                                       | ** ** | **NPI**                     | ** ** | **NPI** | ** ** | **Totals** | ** ** |
| Proved Net  Developed Reserves                   |       |                        |       |   |   |   |   |
| Gas (MMCF)                                       |       | 11,052                      |       | 6,272 |   | 17,324 |   |
|                                             |       |                        |       |   |   |   |   |
| Proved Net  Undeveloped Reserves                 |       |                        |       |   |   |   |   |
| Gas (MMCF)                                       |       | 0                           |       | 0 |   | 0 |   |
|                                             |       |                        |       |   |   |   |   |
| Total Proved  Net Reserves                       |       |                        |       |   |   |   |   |
| Gas (MMCF)                                       |       | 11,052                      |       | 6,272 |   | 17,324 |   |

 

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

 

 

A-4

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EAEC furnished us gas prices in effect atAugust 31, 2005 and with its forecasts of future gas prices which take intoaccount Securities and Exchange Commission guidelines, current market prices,contract prices and fixed and determinable price escalations whereapplicable.  In accordance withSecurities and Exchange Commission guidelines, the future gas prices used inthis report make no allowances for future gas price increases or decreaseswhich may occur as a result of inflation nor do they account for seasonalvariations in gas prices which are likely to cause future yearly average gasprices to be somewhat higher than August gas prices.  In those cases where contract market-out hasoccurred, the current market price was held constant to depletion of thereserves.  In those cases wheremarket-out has not occurred, contract gas prices including fixed anddeterminable escalations, exclusive of inflation adjustments, were used untilthe contract expired and then reduced to the current market price for similargas in the area and held at this reduced price to depletion of the reserves.

 

This report utilized the terms of the gascontract between Eastern Marketing Corporation (a wholly owned subsidiary ofEAEC) and the 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” pricewhich has 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 price 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 expiredin each of the five months prior to each month of such quarter, (ii) the finalsettlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported inthe Wall Street Journal, for such contracts which expire during suchmonth and (iii) the closing settlement prices per MMBtu of Henry Hub GasFutures Contracts for such month, as reported in the Wall Street Journal,for such contracts which expire in each of the six months following suchmonth.  A Henry Hub Gas Futures Contractis defined as a gas futures contract for gas to be delivered to the Henry Hubwhich is traded on the New York Mercantile Exchange.  The weighted average price is determined bygiving the “Fixed” price a 66 2/3 percent weighting and the variable price a 331/3 percent weighting.

 

Since the primary term is complete, thepurchase price under the gas contract will be equal to the “Variable”price.  EAEC computed the “Variable”price under the gas contract as of August 31, 2005 as $9.268 per Mcf, utilizing$8.125 as the Henry Hub Average Spot Price computed in accordance with the gascontract.

 

Operating costs for the leases and wells inthis report were supplied by EAEC and include only costs defined as applicableunder terms of the Trust.  The currentoperating costs were held constant throughout the life of the properties.  This study does not consider the salvage valueof the lease equipment or the abandonment cost.

 

A-5

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No deduction was made for indirect costs suchas general 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 studyof the properties in which the Trust has interests; however, we have not madeany field examination of the properties. No consideration was given in this report to potential environmentalliabilities which may exist nor were any costs included for potential liabilityto restore and clean up damages, in any, caused by past operatingpractices.  EAEC informed us that it hasfurnished us all of the accounts, records, geological and engineering data andreports and other data as were required for our investigation. The ownershipinterests, terms of the Trust, prices, taxes, and other factual data furnishedto us in connection with our investigation were accepted as represented.  The estimates presented in this report arebased on data available through July, 2005.

 

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

 

The reserves included in this report areestimates only and should not be construed as being exact quantities.  They may or may not be actuallyrecovered.  Moreover, estimates of provedreserves may increase or decrease as a result of future operations of EAEC.  Moreover, due to the nature of the NetProfits Interest, a change in the future costs, or prices different from thoseprojected herein may result in a change in the computed reserves and the NetProceeds to the Trust even if there are no revisions or additions to the grossreserves attributed to the property.

 

The future production rates from propertiesnow on production may be more or less than estimated because of changes inmarket demand or allowables set by regulatory bodies.

 

The future prices received by EAEC for thesale of its production may be higher or lower than the prices used in this reportas described 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 thefollowing table which summarizes the total net reserves estimates from combinedinterest of EAEC and the Trust in the Underlying Properties:

 

A-6

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Estimated Net Reserve Data

Certain Combined Leasehold Interests of

Eastern America Energy Corporation

And The Trust

As of September 1, 2005

SEC Parameters

 
| ** **              | ** ** | **Proved**    | ** ** | **Total  Proved** | ** ** |
|-------------------------|------------|---------------|------------|-------------------|------------|
| ** **              | ** ** | **Developed** | ** ** | **Undeveloped**   | ** ** | ** ** |
| Net  Remaining Reserves |       |          |       |              |       |   |   |
|                    |       |          |       |              |       |   |   |
| Gas-MMCF                |       | 35,107        |       | 0                 |       | 35,107 |   |

 

The estimated future net income associatedwith the foregoing volumes and the 10 percent discounted estimated future netincome was $278,698,330 and $113,611,262, respectively.  This evaluation utilizes the same price andcost assumptions that were utilized for evaluating the Trust and discussedearlier in the letter.  The propertieswhich are included in the “Term NPI” were allowed to run for their fulleconomic life in this evaluation.

 

Neither Ryder Scott Company nor any of itsemployees has any interest in the subject properties and neither the employmentto make this study nor the compensation is contingent on our estimates ofreserves and future 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-7

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**SIGNATURES**

 

Pursuant to the requirements of the Securities Exchange Act of 1934,the Registrant has duly caused this report to be signed on its behalf by theundersigned, thereunto duly authorized.

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

 

 

Date:  November 8, 2005

 

TheRegistrant, Eastern American Natural Gas Trust, has no principal executiveofficer, principal financial officer, board of directors or persons performingsimilar functions.  Accordingly, noadditional signatures are available and none have been provided.

 

 

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