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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-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, 2007                  
|OR                                                           
|o                                                             | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|FOR THE TRANSITION PERIOD
FROM                             TO

Commission file number: 1-11748

Eastern American Natural Gas Trust(Exact name of registrant as specified in its Charter)

|Delaware(State or other Jurisdiction of
Incorporation or Organization)                                                                                              |  | 36-7034603(I.R.S. Employer
Identification No.)
|------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------------
|The Bank of New York Trust Company, Trustee
Global Corporate Trust
919 Congress Avenue Suite 500
Austin, TX 78701(Address of principal executive office) (Zip Code)
|(800) 852-1422(Registrant's telephone number, including area code)                                                                                                 

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

Title of Each Class

Name of Each Exchange
On Which RegisteredUnits of Beneficial Interest

New York Stock Exchange


Securities
registered pursuant to Section 12(g) of the Act: None

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange
Act. Yes o    No ý

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment
to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. (See definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act).

|Large accelerated filer o |  | Accelerated filer ý |  | Non-accelerated filer o (Do not check if a smaller reporting company) |  | Smaller reporting company o
|------------------------- |  | ------------------- |  | --------------------------------------------------------------------- |  | ---------------------------

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

As of June 30, 2007, 5,900,000 Units of Beneficial Interest in Eastern American Natural Gas Trust were issued, outstanding and held by
non-affiliates of the registrant (the "Outstanding Units"). Of the Outstanding Units, 19,900 Units of Beneficial Interest (the "Withdrawn Units") have been withdrawn from trading by
voluntary action of Holders and may not be traded unless such Holders comply with certain requirements provided in the related Trust Agreement.

The
aggregate market value of the Outstanding Units minus the Withdrawn Units at the closing sales price on June 30, 2007 of $25.08 was approximately $147 million.

Documents
Incorporated By Reference:None



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TABLE OF CONTENTS



|PART I    
|----------
|Item 1.   
|          
|          
|          
|          
|          
|          
|          
|          
|          
|          
|Item 1A.  
|Item 1B.  
|Item 2.   
|Item 3.   
|Item 4.   
|PART II   
|Item 5.   
|Item 6.   
|Item 7.   
|Item 7A.  
|Item 8.   
|Item 9.   
|Item 9A.  
|Item 9B.  
|PART III  
|Item 10.  
|Item 11.  
|Item 12.  
|Item 13.  
|Item 14.  
|PART IV   
|Item 15.  
|SIGNATURES

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PART I

Item 1.Business

Cautionary Statement

The Trustee (as defined below), its officers or its agents on behalf of the Trustee may, from time to time, make forward-looking statements (other than statements
of historical fact). In addition, this Report on Form 10-K may contain forward-looking statements. When used herein, the words "anticipates," "expects," "believes," "intends" or
"projects" and similar expressions are intended to identify forward-looking statements. To the extent that any forward-looking statements are made, the Trustee is unable to predict future changes in
gas prices, gas production levels, economic activity, legislation and regulation, and certain changes in expenses of the Trust (as defined below). In addition, the Trust's future results of operations
and other forward-looking statements contained in this Item 1, Item 1A and elsewhere 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 described below. The Trustee disclaims any obligations to update forward-looking statements
and all such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph.

Definitions

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

The
following descriptions of the Eastern American Natural Gas Trust (the "Trust"), the Depositary Units, the Net Profits Interests, the Underlying Properties and the calculation of
amounts payable to the Trust, are subject to and qualified in their entirety by the more detailed provisions of the Trust Agreement, the Depositary Agreement, the Conveyances and the Gas Purchase
Contract (each as defined below), all of which are incorporated by reference as exhibits to this Form 10-K and available upon request from the Trustee (as defined below) at the
address set forth herein. The information contained herein relating to the operations of the Underlying Properties, as well as information upon which the reserve figures and financial information
contained herein were derived, was furnished to the Trustee by Eastern American Energy Corporation ("Eastern American").

DESCRIPTION OF THE TRUST

The Trust was formed under the Delaware Business Trust Act pursuant to a Trust Agreement (the "Trust Agreement") among Eastern American, as grantor, Bank of
Montreal Trust Company, as 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 of Montreal Trust Company / Harris Trust, and consequently, The Bank of New York served as trustee of the Trust. On November 20, 2004, the holders of a majority of the Trust Units
voting at a special meeting approved the resignation of The Bank of New York as trustee and depository of the Trust and the appointment of JPMorgan Chase Bank, N.A. as successor trustee of the Trust,
effective as of January 1, 2005. Effective October 2, 2006, The Bank of New York Trust Company, N. A. replaced JPMorgan Chase Bank, N.A. as trustee in connection with the sale by
JPMorgan Chase Bank of substantially all of its corporate trust business to The Bank of New York. Consequently, references herein to the "Trustee" mean Bank of Montreal Trust Company until
May 8, 2000; The Bank of New York as successor Trustee, from May 8, 2000 through December 31, 2004; JPMorgan Chase Bank, N.A. as successor trustee, from January 1, 2005
through October 2, 2006; and The Bank of New York Trust

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Company,
N.A. as successor trustee, effective as of October 2, 2006. The transfer agent for the Trust is Bondholder Communications, an affiliate of The Bank of New York Trust Company, N.A.

The
Trust was formed to acquire and hold net profits interests (the "Net Profits Interests") created from the working interests owned by Eastern American in 650 producing gas wells and
65 proved
development well locations located in West Virginia and Pennsylvania (the "Underlying Properties"). A portion of the production from the wells burdened by the Net Profits Interests was intended to be
eligible for credits ("Section 29 Credits") under the Internal Revenue Code of 1986 for production of gas from Devonian shale or tight formations. The Net Profits Interests to be acquired
consisted of a royalty interest in 322 wells and a term interest in the remaining wells and development well locations. Eastern American was obligated to drill and complete, at its expense, 65
development wells (the "Development Wells") on the development well locations conveyed to the Trust. Eastern American has fulfilled its obligation with respect to the drilling of the Development Wells
(see Note 1 of Financial Statements attached hereto). After May 15, 2012 and prior to or on May 15, 2013 (the "Liquidation Date"), the Trustee is required to sell the remaining
royalty interests and liquidate the Trust.

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

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

The
Trust is responsible for paying the Trustee's fees and all legal, accounting, engineering and stock exchange fees, printing costs and other administrative expenses incurred by or at
the direction of the Trustee. The total fees paid to the Trustee for 2007 were $108,000. The total of all Trustee fees and Trust administrative expenses for 2007 was $621,663. Such costs could
fluctuate in the future depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and engineering services. In addition to such expenses, in 2007,
the Trust paid Eastern American an overhead reimbursement of $339,924. The overhead reimbursement was established at the inception of the Trust, increases by 3.5% per year, and is payable quarterly.

THE NET PROFITS INTERESTS

The Conveyances

The Net Profits Interests ("NPI") were created from the Underlying Properties and conveyed to the Trust pursuant to two Conveyancesone conveying a
royalty interest in specified wells (the "Royalty NPI Conveyance") and the other conveying a term interest in specified wells (the "Term NPI

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Conveyance",
and together with the Royalty NPI Conveyance, the "Conveyances"). Forms of the Conveyances have been incorporated by reference.

The
Underlying Properties are subject to and burdened by the Net Profits Interests. The interests of Eastern American comprising the Underlying Properties represent, on average, a
working interest of approximately 90% and a net revenue interest of approximately 76%. The Conveyances provide that the Trust is only entitled to gas produced from the specific wells identified in the
Conveyances and is not entitled to any gas produced from adjacent wells (including adjacent wells subject to the same lease or farmout agreement as the wells subject to the Net Profits Interests). Gas
produced from the Underlying Properties which is attributable to the Net Profits Interests is purchased from the Trust by Eastern Marketing Corporation ("Eastern Marketing"), a wholly-owned subsidiary
of Eastern American, pursuant to a gas purchase contract (the "Gas Purchase Contract"). The volumes attributable to the Net Profits Interests and the purchase price for such gas is calculated for each
calendar quarter, and payment for such gas is made to the Trust not later than the tenth day of the third calendar month following the end of each calendar quarter.

The
Royalty NPI is not limited in term or amount. Under the Trust Agreement, the Trustee is directed to sell all remaining Royalty NPI after May 15, 2012 and prior to
May 15, 2013, and net proceeds from selling such Royalty NPI will be distributed to Unitholders on the first quarterly payment date following the receipt of such proceeds by the Trust. The Term
NPI will expire on the earlier of May 15, 2013 or such time as 41,683 MMcf of gas has been produced which is attributable to Eastern American's net revenue interests in the properties burdened
by the Term NPI. As of December 31, 2007, 25,419 MMcf of such gas had been produced. The Trust is expected to terminate in 2013. See "Description of Trust Units and Depository
UnitsLiquidation of the Trust".

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

Calculation of Net Proceeds

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

The
Conveyances and the Gas Purchase Contract entitle the Trust to receive an amount of cash for each calendar quarter equal to the Net Proceeds for such quarter. "Net Proceeds" for any
calendar quarter generally 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 the Underlying
Properties less (ii) a volume of gas equal to Chargeable Costs, as defined below, for such quarter, multiplied by (b) the applicable price for such quarter under the Gas Purchase
Contract. If, for any reason, the Gas Purchase Contract terminates prior to the Liquidation Date, "Net Proceeds" will mean 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 the Underlying Properties less (ii) a volume of gas equal to Chargeable Costs for such quarter, multiplied by
(b) the applicable price for such quarter determined in accordance with the Conveyances. Pursuant to the Conveyances, the Trust is not entitled to receive any natural gas liquids produced from
the Underlying Properties or any proceeds relating thereto.

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"Chargeable
Costs" is that volume of gas which equates in value, determined by reference to the relevant sales price under the Gas Purchase Contract or the Conveyances, as applicable, to
the sum of the "Operating Cost Charge", "Capital Costs" and "Taxes" (as defined in the Conveyances). The Operating Cost Charge for 2007 was $588,160, for 2006 was $561,068 and for 2005 was $534,348.
As provided in the Conveyances, the Operating Cost Charge will increase based on the lesser of (A) five percent (5%) or (B) a percentage, not less than zero percent (0%), equal to the
percentage increase, if any, in the average weekly earnings of Crude Petroleum and Gas Production Workers for the last calendar year, as shown by the index of average weekly earnings of Crude
Petroleum and Gas Production Workers, as published 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 Labor Statistics converted all of its industry-based statistics to a different reporting system that was developed in
cooperation with the United States' North American Free Trade Agreement Partners, Canada and Mexico, in an effort to standardize and modernize reporting codes. As a result of this conversion, the
Crude Petroleum and Gas Production Workers index is no longer available for use in the annual calculation of overhead adjustment called for in the various Council of Petroleum Accountants Societies,
or COPAS, model forms after March 2003.

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

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

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

The
Conveyances require Eastern American to maintain books, records, and accounts sufficient to calculate the volumes of gas and the share of Net Proceeds payable to the Trust. Eastern
American provides to the Trust quarterly and annual statements of applicable production, revenues, and costs necessary for the Trust to prepare quarterly and annual financial statements with respect
to the Net Profits Interests and the Underlying Properties. The financial statements of the Trust are audited annually at the Trust's expense.

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Gas Purchase Contract

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

Under
the Gas Purchase Contract, Eastern Marketing purchases gas from the Trust at a variable price for each quarter equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus
$0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter equal to the
price obtained with respect to each of the three months in such quarter, in the manner specified below, and then taking the average of the prices determined for each of such three months. The price
determined for any month of such quarter is equal to the average of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in The Wall Street Journal,for such 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 inThe Wall Street Journal,for such contracts which expire during such month and
(iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures Contracts determined as of the contract settlement date for such month, as reported inThe Wall
Street Journal,for such contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to
be delivered to the Henry Hub, which is traded on the New York Mercantile Exchange.

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

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

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

Performance Support for Gas Purchase Contract

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

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Distributions and Income Computations

The Trustee determines for each quarter the amount of cash available for distribution to holders of Depositary Units and the Trust Units evidenced thereby. Such
amount (the "Quarterly Distribution Amount") is equal to the excess, if any, of (i) the cash that the Trust receives on or before the tenth day of the third month after the end of each calendar
quarter ending before the Trust is dissolved and that is attributable to production from the Net Profits Interest held by the Trust during that calendar quarter, plus, with certain exceptions, any
other cash receipts of the Trust during such quarter, over (ii) the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter
in any cash reserves established for the payment of contingent or future obligations of the Trust. Quarterly Distribution Amounts for each of the quarters in 2007 were $0.5308, $0.5667, $0.5228 and
$0.4995, respectively. Based on the payment procedures relating to the Net Profits Interests, cash received by the Trustee in a particular quarter from the Net Profits Interests reflects actual gas
production for a portion of such quarter and a production estimate for the remainder of such quarter, such estimate to be adjusted to actual production in the following quarter. The Quarterly
Distribution Amount for each quarter is payable to Unitholders of record on the last day of the second month following the end of such calendar quarter or such later date as the Trustee determines is
required to comply with legal or stock exchange requirements ("Quarterly Record Date"). It is
expected that the Trustee will continue to be able to distribute cash on or before the 15th day (or the next succeeding business day following such day if such day is not a business day) of the
third month following the end of each calendar quarter to each person who was a Unitholder of record on the Quarterly Record Date, together with interest earned on such Quarterly Distribution Amount
from the date of receipt thereof by the Trustee to the payment date.

The
net taxable income of the Trust for each calendar quarter is reported by the Trustee for tax purposes as belonging to the holders of record to whom the Quarterly Distribution Amount
was or will be distributed. Assuming that the Trust will be classified for tax purposes as a "grantor trust," the net taxable income will be realized by the holders for tax purposes in the calendar
quarter received by the Trustee, rather than in the quarter distributed by the Trustee. Thus, a Unitholder's taxable income for a taxable year may differ from the cash the Unitholder receives during
that year. In addition, taxable income of a holder will differ from the Quarterly Distribution Amount because the Treasury Obligations will be treated as generating interest income for tax purposes.
There may also be minor variances because of the possibilities that a reserve will be established in one quarter that will not give rise to a tax deduction until a subsequent quarter, an expenditure
paid for in one quarter will have to be amortized for tax purposes over several quarters, or for other reasons. See "Federal Income Tax Matters."

Each
holder of Depositary Units (including the underlying Trust Units) of record as of the record date for the final quarter of the Trust's existence in accordance with the Trust
Agreement will be entitled to receive a liquidating distribution equal to a pro rata portion of the net proceeds from the sale of the Royalty NPI (to the extent not previously distributed) and a pro
rata portion of the proceeds from the matured Treasury Obligations.

Sale and Abandonment of Underlying Properties; Sale of Royalty NPI

Eastern American and any transferees have the right to abandon any well or working interest included in the Underlying Properties if, in its opinion, such well or
property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the potential conflict of interest between Eastern American and the Trust in
determining whether a well is capable of producing in paying quantities, Eastern American is required under the Conveyances to make any such determination as would a reasonably prudent operator in the
Appalachian Basin if it were acting with respect to its own properties, disregarding (i) the existence of the Net Profits Interests as a burden on such property and (ii) the direct or
indirect effect, financial or otherwise, on Eastern American or any

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of
its affiliates that may result from the performance by Eastern Marketing of its obligations under the Gas Purchase Contract.

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

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

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

THE UNDERLYING PROPERTIES

General

The Underlying Properties are comprised of Eastern American's working interests in certain properties located in the Appalachian Basin states of West Virginia and
Pennsylvania. As of December 31, 2007, such properties consisted of 670 producing gas wells. The working interests of Eastern American comprising the Underlying Properties are held under leases
and farmout agreements with third parties. Such working interests are subject to landowner's royalties (typically 121/2%) and may be subject to additional royalties or other obligations
burdening the working interests. Such royalties do not bear lease operating expenses, but reduce the revenue interests attributable to the Underlying Properties. Eastern American's interests
comprising the Underlying Properties represent, on average, a working interest of approximately 90% and a net revenue interest of approximately 76%. As of December 31,
2007, proved developed reserves attributable to the Net Profits Interests (reflecting quantities of gas free of future costs and expenses based on estimated prices) were approximately 13,837 MMcf.
(See "Reserves").

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

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

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

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

A
farmout agreement is typically an agreement under which a lessee under an oil and gas lease (the "Farmor") grants to another party the right to drill wells on the tract covered by such
lease and to earn certain acreage for drilling such wells. In the Appalachian Basin, the Farmor generally receives a well location fee and reserves an overriding royalty interest in the wells which
typically ranges from 3.25%
to 6.25%. Farmout agreements typically provide that wells must be drilled and completed as a condition to a transfer by the Farmor of the interest in the underlying lease.

Reserves

Proved Reserves of Underlying Properties and Net Profits Interests.The following table sets forth, as of December 31,
2007, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties, the Royalty NPI and the Term NPI, in each
case derived from a report of oil and gas reserves attributable to the Trust as of December 31, 2007 prepared by Ryder Scott Company (the "Reserve Report"). Proved reserve quantities
attributable to the Net Profits Interests are calculated by subtracting an amount of gas sufficient, if sold at the prices used in preparing the reserve estimates, to pay the future estimated costs
and expenses deducted in the calculation of Net Proceeds. Accordingly, the reserves attributable to the Net Profits Interests reflect quantities of gas that are free of future costs or expenses if the
price and cost assumptions set forth in the Reserve Report occur. A decrease in the price assumption, or an increase in the cost assumption used in the Reserve Report would reduce the estimates of
proved reserves, future net revenues and discounted future net revenues, set forth herein and in the Reserve Report. The Term NPI excludes production beyond the earlier of May 15, 2013 or such
time as 41,683 MMcf of gas has been produced which is attributable to Eastern American's net revenue interests in the properties burdened by the Term NPI. The discounted present value of estimated
future net revenues was determined using a discount rate of 10% in accordance with applicable requirements. A copy of the Reserve Report is included as Exhibit A hereto.

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|                         |                        | Proved Gas Reserves |       |        |        |       
|------------------------ | ---------------------- | ------------------- | ----- | ------ | ------ | ------
|
|
|Underlying Properties(1) |                        | 27,591              |       | 0      |        | 27,591
|                         |                        |                     |       |        |        |       
|                         | Net Profits Interests: |                     |       |        |        |       
|                         |                        | Royalty NPI         |       | 10,012 |        | 0     
|                         |                        | Term NPI            |       | 3,825  |        | 0     
|                         |                        |                     |       |        |        |       
|                         |                        |                     | Total |        | 13,837 |       
|                         |                        |                     |       |        |        |       

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The
value of the Depositary Units and the Trust Units evidenced thereby are substantially dependent upon the proved reserves and production levels attributable to the Net Profits
Interests. There are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the timing of development expenditures, if any.
The reserve data set forth herein, although prepared by independent engineers in a manner customary in the industry, are estimates only, and actual quantities and values of gas are likely to differ
from the estimated amounts set forth herein. In addition, the discounted present values shown herein were prepared using guidelines established by the Securities and Exchange Commission (the
"Commission") and the Financial Accounting Standards Board for disclosure of reserves and should not be considered representative of the market value of such reserves or the Depositary Units or the
Trust Units evidenced thereby. A market value determination would include many additional factors.

COMPETITION AND MARKETS

All of the production attributable to the Net Profits Interest is sold to Eastern Marketing pursuant to the Gas Purchase Contract. See "The Net Profits
InterestsGas Purchase Contract."

REGULATION OF NATURAL GAS

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

Drilling
and production of natural gas are heavily regulated in Pennsylvania and West Virginia, as in most states. A well cannot be drilled without a permit, and operations must be
conducted in compliance with environmental, safety and conservation laws and regulations. In contrast to many other

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states
which have substantial oil and gas production activity, the spacing of shallow wells (such as the wells subject to the Net Profits Interests) is not regulated by any state statute or regulatory
agency in either West Virginia or Pennsylvania. Without spacing requirements specified by state statute or regulation, drainage of reserves from a property may occur from wells located in close
proximity to such property.

HEALTH, SAFETY, AND ENVIRONMENTAL REGULATION

General.Activities on the Underlying Properties are subject to existing 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 existing Federal, state and local laws,
rules and regulations regulating health, safety, the discharge of materials into the environment or otherwise relating to the protection of the environment will not have a material adverse effect upon
the Trust. It cannot be predicted what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment
resulting from operations on the Underlying Properties could have on the Trust. However, pursuant to the terms of the Conveyances, any costs or expenses incurred in connection with environmental
liabilities of Eastern American arising out of or related to activities occurring on or in, or conditions existing on or under, the Underlying Properties before the effective date of the Conveyances
will be borne by Eastern American and will not be deducted in calculating Net Proceeds attributable to the Net Profits Interests. Additionally, because Unitholders will have limited liability in
accordance with the Trust Agreement and Delaware law, Unitholders should be shielded from direct liability for any environmental liabilities. See "Description of Trust Units and Depositary
UnitsLiability of Unitholders." However, costs and expenses incurred by Eastern American for certain Capital Costs associated with environmental liabilities arising after the effective
date of the Conveyances would reduce Net Proceeds, and would therefore be borne, in part, by the Unitholders. The following subtopics discuss some of the principal forms of health, safety, and
environmental regulation to which the Underlying Properties and operations thereon are subject. The costs of complying with these
regulatory requirements may burden the Net Profits Interests to the extent they arise out of or are related to activities occurring on or in, or conditions existing on or under, the Underlying
Properties after the effective date of the Conveyances.

Solid and Hazardous Waste.The Underlying Properties include numerous properties that have produced gas for a number of years
but in which Eastern American has held an interest for a relatively short period of time prior to the effective date of the Conveyances. Eastern American has informed us they have no knowledge of
prior operators utilizing operating and disposal practices that were not standard in the industry at the time nor have hydrocarbons or other solid or hazardous wastes may have been disposed of or
released on or under the Underlying Properties. Federal, state and local laws applicable to gas-related wastes have become increasingly more stringent. Under current laws, Eastern American
or the operator of the Underlying Properties could be required to remove or remediate previously disposed wastes or property contamination (including groundwater contamination) or to perform remedial
plugging operations to prevent future contamination.

The
operations of the Underlying Properties may generate wastes that are subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The
Environmental Protection Agency (the "EPA") has limited the disposal options for certain hazardous wastes and may adopt more stringent disposal standards for nonhazardous wastes.

Superfund.The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "superfund"
law, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment.
These persons include the current or previous owner and operator of a site and companies that disposed or arranged for the disposal of, the hazardous substance found at a

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site.
CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible
classes of persons of the costs of such action. In the course of their operations, the operators of the Underlying Properties have generated and will generate wastes that may fall within CERCLA's
definition of "hazardous substances". Eastern American or the previous operator of the Underlying Properties may be responsible under CERCLA for all or part of the costs to clean up sites at which
such substances have been disposed.

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

OSHA.The operations of the Underlying Properties are subject to the requirements of the Federal Occupational Safety and
Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund
Amendment and Reauthorization Act and similar state statutes require that information be organized and maintained about hazardous materials used or produced in the operations. Certain of this
information must be provided to employees, state and local government authorities and citizens.

DESCRIPTION OF TRUST UNITS AND DEPOSITARY UNITS

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

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

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

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

Withdrawal of Trust Units and Restrictions on Transfer

Upon presentation of Depositary Units in denominations of 50 or integral multiples thereof for withdrawal of the Trust Units and discrete Treasury Obligations
evidenced thereby in accordance with the Deposit Agreement, the Unitholder will receive an uncertificated direct interest in Trust Units. These withdrawn Trust Units will be evidenced on the books of
the Trustee by a transfer of such Trust Units from the name of the Depositary to the name of the withdrawing Unitholder. Holders of

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withdrawn
Trust Units will be entitled to receive Trust distributions and periodic Trust information (including tax information) directly from the Trustee. Moreover, holders of Trust Units will be
entitled to each of the rights accorded Unitholders under the Trust Agreement, including voting and liquidation rights, as elsewhere described herein, except that withdrawn Trust Units are not freely
transferable as described below.

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

Distributions and Income Computations

The Trustee determines for each quarter the Quarterly Distribution Amount available for distribution to holders of Depositary Units and the Trust Units evidenced
thereby. The Quarterly Distribution Amount is equal to the excess, if any, of (i) the cash that the Trust receives on or before the tenth day of the third month after the end of each calendar
quarter ending before the Trust is dissolved and that is attributable to production from the Net Profits Interest held by the Trust during that calendar quarter, plus, with certain exceptions, any
other cash receipts of the Trust during such quarter, over (ii) the liabilities for the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such
quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. Based on the payment procedures relating to the Net Profits Interests, cash received by the
Trustee in a particular quarter from the Net Profits Interests reflects actual gas production for a portion of such quarter and a production estimate for the remainder of such quarter, such estimate
to be adjusted to actual production in the following quarter. The Quarterly Distribution Amount for each quarter is payable to Unitholders of record on the Quarterly Record Date, which is the last day
of the second month following the end of such calendar quarter or such later date as the Trustee determines is required to comply with legal or stock exchange requirements. The Trustee generally is
able to distribute cash on or before the 15th day (or the next succeeding 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 person who was a Unitholder of record on the Quarterly Record Date, together with interest earned on such Quarterly Distribution Amount from the date of receipt thereof by the
Trustee to the payment date.

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

Each
holder of Depositary Units (including the underlying Trust Units) of record as of the record date for the final quarter of the Trust's existence will be entitled to receive a
liquidating distribution equal to a pro rata portion of the net proceeds from the sale of the Royalty NPI (to the extent not previously distributed) and a pro rata portion of the proceeds from the
matured Treasury Obligations.

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Possible Divestiture of Depositary Units and Trust Units

The Trust Agreement imposes no restrictions based on nationality or other status of holders of Trust Units. However, the Trust Agreement and the Deposit Agreement
provide that in the event of certain judicial or administrative proceedings seeking the cancellation or forfeiture of 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 Units including holders of Depositary Units, the Trustee will give written notice thereof to each holder whose nationality,
citizenship or other status is an issue in the proceeding, which notice will constitute a demand that such holder dispose of his Depositary Units or withdrawn Trust Units within 30 days. If any
holder fails to dispose of his Depositary Units or withdrawn Trust Units in accordance with such notice, cash distributions on such units are subject to suspension. In the event a holder fails to
dispose of Depositary Units in accordance with such notice, the Depositary may cancel such holder's Depositary Units and reissue them in the name of the Trustee, whereupon the Trustee will use its
reasonable efforts to sell the Depositary Units and remit the net sale proceeds to such holder. In the case of Trust Units withdrawn from deposit with the Depositary, the Trustee shall redeem such
Trust Units not divested in accordance with such notice, for a cash price equal to the then-current market price of the Depositary Units less the then-current
over-the-counter bid price of the related, withdrawn Treasury Obligations. The redemption price will be paid out in quarterly installments limited to the amount that otherwise
would have been distributed in respect of such redeemed Trust Units.

Liability of Unitholders

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

Liquidation of the Trust

The Trust will be liquidated and the Royalty NPI will be sold prior to the Liquidation Date, which is expected to occur in 2013. Unitholders of record as of the
record date for the final quarter of the
Trust's existence will be entitled to receive a terminating distribution with respect to each Depositary Unit equal to a pro rata portion of the net proceeds from the sale of the Royalty NPI (to the
extent not previously distributed) and a pro rata portion of the proceeds from the matured Treasury Obligations. Under the Trust Agreement, Eastern American has 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 tax matters of general application which addresses the material tax consequences of the ownership and sale of
Depositary Units. This section provides a generalized summary of certain federal income tax matters of general application relating to ownership and sale of Depositary units by individuals who are
citizens or residents of the United States. Accordingly, the following discussion has only limited application to domestic corporations and persons subject to specialized Federal income tax treatment,
such as tax-exempt entities (including IRAs), regulated investment companies and insurance companies. The following discussion also does not address tax consequences to foreign persons. It
is impractical to comment on all aspects of Federal laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in Depositary Units as they relate to the
particular circumstances of every prospective Unitholder. Each Unitholder should consult his own tax advisor with respect to his particular circumstances including, his alternative minimum tax
circumstances.

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This
summary is based on current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), existing and proposed regulations thereunder and current administrative rulings
and court decisions, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the
Internal Revenue Service ("IRS").

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

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

Reports

Unitholders of record are provided informational tax packages in order to permit computation of their taxable income from ownership of Depositary Units.

Treatment of Depositary Units

Purchasers of Depositary Units are treated, for Federal income tax purposes, as purchasing directly an interest in the Treasury Obligations and a Trust Unit.
Purchasers are therefore required to allocate the purchase price of their Depositary Unit between the interest in the Treasury Obligations and the Trust Unit in the proportion that the fair market
value of each bears to the fair market value of the Depositary Unit. Information regarding purchase price allocations is furnished to Unitholders by the Trustee.

Classification and Taxation of the Trust

For federal income tax purposes, the Trust has been treated and expects to continue to be treated not as an association taxable as a corporation, but as a grantor
trust that is not subject to Federal income tax as an entity separate from its beneficial owners. For tax purposes, Unitholders are considered to own and receive the Trust's assets and income as
though no trust were in existence. The Trust has historically filed an information return, reporting all items of income, credit or deduction which must be included in the tax returns of the
Unitholders. (See Reporting Requirements for Widely-Held Fixed Investment Trusts, below.) If the Trust were determined not to be a grantor trust, it is expected that it would be treated
either as a partnership subject to the publicly traded partnership rules under the Code or as an association taxable as a corporation. If the Trust were treated as a publicly traded partnership, it is
believed that the Trust's various items of income and deduction would still be taxable to the Unitholders on a current, flow-through basis as partners of a partnership and not to the Trust
as an association taxable as a corporation. If the Trust were determined to be an association taxable as a corporation, it would be treated as a separate entity subject to corporate tax on its taxable
income, Unitholders would be treated as shareholders, and distributions to Unitholders from the Trust would be treated as nondeductible corporate distributions. Such distributions would be taxable to
a Unitholder, first, as dividends to the extent of the Unitholder's pro rata share of the Trust's

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earnings
and profits, then as a tax-free return of capital to the extent of his basis in his Trust Units, and finally as capital gain to the extent of any excess.

Reporting Requirements for Widely-Held Fixed Investment Trusts

Under new IRS regulations, effective for the trust tax reporting requirements after December 31, 2006, the Trust is classified as a widely-held
fixed investment trust (WHFIT). Effective for the calendar year ended December 31, 2007, the Trust will no longer be required to file an information return reporting the items of income, credit
or deduction that would be allocated to the unitholders based on their investment in the Trust. Effective for 2007 and subsequent years, the regulations require the sharing of tax information among
trustees and intermediaries that hold a trust interest on behalf of or for the account of a beneficial owner or any representative or agent of a trust interest holder of fixed investment trusts that
are classified as widely-held fixed investment trusts. The new reporting requirements provide for the dissemination of trust tax information by the Trustee to intermediaries who are
ultimately responsible for reporting the investor-specific information through Forms 1099 to the investors and the Internal Revenue Service. Every trustee or intermediary that is required to
file a Form 1099 for a Trust interest holder must furnish a written tax information statement that is in support of the amounts as reported on the applicable Form 1099 to the
Trust interest holder. Any generic or customized tax information provided by the Trustee of Eastern American Natural Gas Trust is intended to only be used to assist Unitholders in the preparation of
their 2007 federal and state income tax returns.

Available Trust Tax Information

In compliance with the new reporting requirements for widely-held fixed investment trusts and the dissemination of trust tax reporting information,
the Trustee provides a generic tax information reporting booklet which is intended only to be used to assist Unitholders in the preparation of their 2007 federal and state income tax returns. This tax
information booklet can be obtained at www.businesswire.com/cnn/ngt.htm

Direct Taxation of Unitholders

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

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

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

Based
upon future market conditions, forecasted taxable income may exceed forecasted distributable cash, and the amount of such excess could be significant. Such estimates are based on
numerous assumptions as to the allocation of a Unitholder's purchase price and the amount and treatment of operating costs, development costs, Trust administrative expenses, production estimates and
depletion. No assurance can be given that the estimates will prove to be correct, and the actual relationship between distributable cash and taxable income could be materially different.

Treatment of Trust Units

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

Interest Income

The Term NPI is treated as a "production payment" under Section 636(a) of the Code. Thus, Unitholders are treated as making a mortgage loan on the
Underlying Properties of the Term NPI to Eastern American in an amount equal to the amount of the purchase price of each Depositary Unit allocated to the Term NPI. Because it is treated as a debt
instrument for tax purposes, the Term NPI is subject to the original issue discount income ("OID") rules of the Code which generally require the periodic inclusion of the original issue discount in
income of the purchaser of a debt instrument. The Code also authorizes the IRS to prescribe regulations modifying the statutory provisions where, by reason of contingent payments such as those
provided for by the Term NPI, the tax treatment provided under the Code provisions does not carry out the purposes of such provisions.

The
IRS has issued a series of proposed and final regulations dealing with debt instruments which call for contingent payments. The initial set of proposed regulations dealing with this
topic were issued on April 8, 1986, and modified on February 26, 1991 (the "Old Proposed Regulations"). A second set of proposed contingent payment regulations were issued on
January 19, 1993, but were withdrawn prior to publication in the Federal Register. On December 15, 1994, the IRS replaced the Old Proposed Regulations by issuing a third set of proposed
regulations addressing debt obligations that provide for contingent payments (the "New Proposed Regulations"). The New Proposed Regulations were proposed to be effective for debt obligations issued on
or after the date that is sixty days following the promulgation of the New Proposed Regulations in final form. In this regard, the New Proposed Regulations have been adopted in final form (the "Final
Regulations"), though effective only 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 Term
NPI. However, the Preamble to the Final Regulations provides that for debt instruments issued prior to the effective date of the Final Regulations, a taxpayer
may use any reasonable method to account for such debt instruments, including a method that would have been permitted under the proposed regulations when the debt instrument was issued.

The
Trustee understands that, in accordance with the foregoing, Eastern American, as obligor under the Term NPI, intends to continue to treat the Term NPI in the manner provided under
the Old Proposed Regulations, which were proposed at the time the Term NPI was transferred to the Trust and Trust Units were issued. Under this approach, each payment (at the time the amount of such
payment

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becomes
fixed) made to the Trust with respect to the Term NPI will be treated first as a payment of interest to the extent of interest deemed accrued under the OID rules and the excess (if any) will
be treated as a payment of principal. The total amount treated as principal will be limited to a portion of the purchase price of each Depositary Unit allocated to the Term NPI. For purposes of
determining the amount of accrued interest, the Old Proposed Regulations required the use of the Applicable Federal Rate based on the due date of the final payment due under the terms of the
production payment, which for the Term NPI is May 15, 2013.

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

Royalty Income and Depletion

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

The
allowance for depletion with respect to a property is 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 or retailers of oil or gas or their primary products) on the equivalent of 1,000 barrels of
production per day. Percentage depletion
is a statutory allowance equal to 15% of the gross income from production from a property which is included in income by a taxpayer.

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

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

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Section 29 Credit

The Trustee has been informed by Eastern American that most of the production attributable to the Royalty NPI is gas produced from Devonian shale or a tight
formation. Provided a number of requirements are met, taxpayers are entitled to the Section 29 Credit for gas produced from Devonian shale or a tight formation. The Section 29 Credit
generally applies only to gas produced from Devonian shale or a tight formation in the United States and sold to an unrelated party prior to January 1, 2003, from wells drilled after
December 31, 1979, and prior to January 1, 1993. Additionally, the Section 29 Credit applies only to gas produced from 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 is produced from a well drilled
after November 5, 1990. A Unitholder is eligible to claim the Section 29 Credit with respect to certain sales of such gas attributable to the Royalty NPI. Under current law, the
Section 29 credit is no longer available for production after December 31, 2002.

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

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

On
March 23, 1999, the United States Tax Court of Appeals for the Tenth Circuit affirmed a lower court decision inTrue Oil Company
v.C.I.R. 170 F.3d 1294. The Court ruled that, in order to be eligible for credits under Section 29 of the Internal
Revenue Code, each well from which gas is produced from Devonian shale or a tight formation must receive a determination from the Federal Energy Regulatory Commission ("FERC") that the gas produced
is, in fact, produced from Devonian shale or a tight formation. Eastern American has verified that most producing gas wells subject to the Royalty NPI have received a well category determination from
FERC. Should the Internal Revenue Service challenge the amount of the Trust's production qualifying for Section 29 Credits, a Unitholder might not
be able to claim the benefit of Section 29 credits for production attributable to a well that did not receive a FERC determination. If successful, such a challenge could affect the tax
reporting for such credits for tax years examined by the IRS and any subsequent tax years. However, it should be noted that under current law the Section 29 credit is no longer available for
production after December 31, 2002.

Other Income and Expenses

From time to time, the Trust may generate interest income on funds held as a reserve or held until the next distribution date. Expenses of the Trust include
administrative expenses of the Trustee. Under the Code, certain miscellaneous itemized deductions of an individual taxpayer are deductible only to the extent that in the aggregate they exceed 2% of
the taxpayer's adjusted gross income. Certain administrative expenses attributable to the Trust Units may have to be aggregated with an individual Unitholder's other miscellaneous itemized deductions
to determine the excess over 2% of adjusted gross income. To date, the amount of such expenses has not been significant in relation to the Trust's income.

20

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Alternative Minimum Tax

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

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

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

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

Non-Passive Activity

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

Unrelated Business Taxable Income

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

Sale of Depositary Units; Sale of Trust Units or Treasury Obligations

Generally, a Unitholder will realize gain or loss on the sale or exchange of his Depositary Units measured by the difference between the amount realized on the
sale or exchange and his adjusted basis for such Depositary Units. Gain or loss on the sale of Depositary Units by a Unitholder who is not a dealer with respect to such Depositary Units and who has a
holding period for the Depositary Units of more than one year will be treated as long-term capital gain or loss, except to the extent of the depletion recapture amount and any accrued
market discount as explained below. A Unitholder's initial basis in his Depositary Units is equal to the amount paid for such Depositary Units. Such basis is increased by the amount of OID income
recognized by the Unitholder attributable to the Treasury Obligations. Such basis is reduced by deductions for depletion claimed by the Unitholder (but not

21

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below
zero). In addition, such basis is reduced by the amount of any payments attributable to the Term NPI which are treated as payments of principal under the OID rules.

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

A
Unitholder who allocates his purchase price (or is required to allocate his purchase price) to the Treasury Obligations in an amount less than the sum of (a) his share of the
initial issue price of the Treasury Obligations and (b) his share of OID income recognized by prior holders of the Treasury Obligations (any such difference represents "market discount") will
generally be required to recognize ordinary income to the extent of any accrued market discount upon sale of the Depositary Units. In general, accrued market discount is an amount which bears the same
ratio to total market discount as the number of days which a Unitholder holds a Depositary Unit bears to the number of days after the date the Unitholder acquired the Depositary Unit and up to and
including the Liquidation Date.

Withdrawal of Trust Units or Treasury Obligations

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

Sale of Net Profits Interests or Production Payment

A sale by the Trust of Net Profits Interests are treated for Federal income tax purposes as a sale of Net Profits Interests by a Unitholder. Thus, a Unitholder
will recognize gain or loss on a sale of Net Profits Interests by the Trust. A portion of that income may be treated as ordinary income to the extent of depletion recapture. Receipt by the Trust of
proceeds drawn from the letter of credit supporting Eastern Marketing's obligations under the Gas Purchase Contract is, in certain cases, in consideration for the conveyance to Eastern Marketing of a
production payment interest in reserves attributable to the Net Profits Interests or to compensate the Trust for damages from a breach of the Gas Purchase Contract. All or a portion of such proceeds
may be treated as non-taxable loan proceeds attributable to a loan by Eastern Marketing resulting from the production payment, may be treated as ordinary income not subject to depletion or
may receive some other treatment, depending upon facts existing at that time. To the extent receipt of such proceeds is attributable to a sale of reserves by the Trust, depletion and Section 29
Credits available to the Unitholders for subsequent periods is reduced.

Backup Withholding

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

Tax Shelter Registration

The Trust has been registered with the IRS as a "tax shelter," and has received tax shelter registration number 93040000163. A "tax shelter," for purposes
of the registration requirement, is an investment with respect to which a person could reasonably infer, from the representations made in

22

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connection
with any offer for sale of any interest in the investment, that the "tax shelter ratio" for any investor may be greater than two to one as of the close of any of the first five years ending
after the date on which the investment is offered for sale. The term "tax shelter ratio" with respect to an investment means the ratio that the aggregate amount of gross deductions for any investor,
determined without regard to income derived from the investment, plus 350% of the credits that are potentially available to an investor, bears to 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 any other property invested. Certain borrowings, however, including those from other participants
in the venture, are excluded from the investment base. While Eastern American has no knowledge of any such borrowings, it is possible that, due to such borrowings, the investment base of an investor
would be substantially reduced or eliminated.

A
Unitholder who sells or otherwise transfers a Trust Unit must furnish to the transferee the tax shelter registration number set forth above. The penalty for failure of the transferor
of a Trust Unit to furnish such tax shelter registration number to a transferee is $100 for each such failure. Unitholders must disclose the tax shelter registration number of the 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 of the Trust is included. A Unitholder who fails to
disclose the tax shelter registration number on his return, without reasonable cause for such failure, will be subject to a $50 penalty for each such failure. (Any penalties discussed herein are not
deductible for income tax purposes.)

ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE 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 of certain information regarding state income taxes and other state tax matters affecting individual Unitholders.
Unitholders are urged to consult their own legal and tax advisors with respect to these matters.

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

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

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

23

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Available Information

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

Item 1A.Risk Factors.

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

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

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



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



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



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

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None of the Trust, the Trustee nor the Unitholders has any control over the operation of the properties.

None
of the Trust, Trustee nor the Unitholders is able to influence or control the operation of the properties. All of the wells are operated by Eastern American. As operator, Eastern
American has the right to abandon or sell any well if, in its opinion, the well or property ceases to produce or is not capable of producing in commercially paying quantities. In general, upon
abandonment of any well to which the Net Profits Interests relate, that portion of the Net Profits Interests will be extinguished.



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



The production, transportation and sale of natural gas from the wells to which the Net Profits Interest relate are subject to governmental regulation. Compliance
with these regulations may be expensive.



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



Administrative costs, including professional services fees and expenses, are deducted prior to distributions to Unitholders. Consequently, administrative costs
adversely affect distributions to Unitholders.

The legal status of the Net Profits Interests under some circumstances is unclear.

At
the time of the formation of the Trust, Eastern American noted that it was likely that the Net Profits Interests would not be treated as real property interests under the laws of West
Virginia and
Pennsylvania. Nevertheless, Eastern American recorded the Conveyances in the real property records of West Virginia and Pennsylvania in accordance with local recording acts. Eastern American believes
that, if, during the term of the Trust, Eastern American becomes involved as a debtor in a bankruptcy proceeding under the Federal Bankruptcy Code, the Net Profits Interests relating to the Underlying
Properties located in West Virginia would be treated as fully conveyed personal property interests. However, if the Conveyances were held to constitute executory contracts, and, if such contracts were
not to be assumed in a bankruptcy proceeding, the Trust probably would be treated as an unsecured creditor of Eastern American. With respect to the properties located in Pennsylvania, which
represented approximately 10% of the reserves attributable to the Net Profits Interests at the inception of the Trust, Eastern American believed that there is a greater risk that the Net Profits
Interests would not be treated as fully conveyed property interests and instead the Conveyances could be treated as executory contracts, meaning that the Trust could be treated as an unsecured
creditor with respect to those interests.

25

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The Net Profits Interests are subject to any defects in Eastern American's rights to the Underlying Properties.

The
Net Profits Interests are subject to any defects in Eastern American's rights with respect to the Underlying Properties. Eastern American believes that its interests with respect to
the Underlying Properties are good and defensible in accordance with standards generally accepted in the Appalachian oil and gas industry, subject to exceptions which do not detract substantially from
the value of its interests. However, it is possible that leases or farmout agreements could be treated as executory contracts if the third party lessor or farmor under a farmout agreement were to
become a debtor in bankruptcy, meaning that it is possible that a lease or farmout agreement could be rejected in a bankruptcy proceeding.

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

At
the inception of the Trust, Eastern American received an opinion of counsel that the Trust is a grantor trust and not an association taxable as a corporation for Federal income tax
purposes, and that each Unitholder would be taxed directly on his pro rata share of the income attributable to assets of the Trust and, subject to certain limitations, would be entitled to claim
depletion deductions and tax credits attributable to the Royalty NPI and would be entitled to claim his pro rata share of other deductions attributable to assets of the Trust. However, the opinion of
counsel is not binding on the IRS or any court.



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



The interests of Eastern American and the interests of the Trust and the Unitholders may at times be different. For example, Eastern American's interests may
conflict with those of the Trust and Unitholders in situations involving the development, operation or abandonment of the Underlying Properties or adjacent properties. In making decisions with respect
to such operations, or otherwise with respect to the development, operation or abandonment of the Underlying Properties, Eastern American is required to act as a reasonably prudent operator in the
Appalachian Basin would act with respect to its own properties, without regard to the existence of the Net Profits Interests and without regard to any possible adverse effect on Eastern Marketing or
Eastern American under the Gas Purchase Contract. In addition, Eastern American has agreed not to drill any well within 1,000 feet of any well subject to the Net Profits Interests which produces oil
or gas from the same formations or horizons as any such producing well. These covenants would not prohibit Eastern American from drilling additional wells on the same property as the wells subject to
the Net Profits Interests provided that Eastern American complies with both of these covenants. In addition, these covenants would not prohibit Eastern American from drilling development wells on
adjacent properties provided that Eastern American complies with the 1,000 foot limitation. If Eastern American is permitted under these covenants to drill additional development wells near the wells
subject to the Net Profits Interests, the additional wells could cause drainage of the reserves attributable to the Net Profits Interests. These covenants apply only to Eastern American, and do not
apply to third parties.

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In addition, Eastern American's interests may conflict with those of the Trust and the Unitholders in situations involving the sale of Underlying Properties. Eastern American has the
right to sell all or any portion of the Underlying Properties without restrictions; however, except in limited circumstances where Eastern American may require the Trust to release the Net Profits
Interests, the Conveyances provide that the purchaser of any of the Underlying Properties will acquire such Underlying Properties subject to the Net Profits Interests. The Conveyances provide that a
purchaser will be subject to the same standards of conduct with respect to development, operation and abandonment of such Underlying Properties as are applicable to Eastern American. Eastern American
has the right, subject to limitations, to cause the Trust to release a portion of the Net Profits Interests in connection with a sale of a portion of the Underlying Properties.



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



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



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

None of the Trustee, the Trust nor the Unitholders has any control over the operation of the Underlying Properties.

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

Item 1B.Unresolved Staff Comments.

None.

Item 2.Properties.

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

Item 3.Legal Proceedings.

None.

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

None.

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PART II

Item 5.Market for Registrant's Common Equity, Related Unitholders Matters and Issuer Purchases of Equity  Securities.

The
Depositary Units are traded on the New York Stock Exchange under the ticker symbol "NGT." The high and low prices and distributions paid during the quarters in the
two-year period ended December 31, 2007 were as follows:

Quarter

High

Low

Distributions Paid2006:First (to March 31, 2006)

$
28.65

$
26.71

$
0.74Second (to June 30, 2006)

$
29.64

$
27.00

$
0.64Third (to September 30, 2006)

$
30.75

$
25.20

$
0.65Fourth (to December 31, 2006)

$
28.80

$
25.22

$
0.452007:First (to March 31, 2007)

$
29.07

$
24.98

$
0.53Second (to June 30, 2007)

$
27.17

$
24.97

$
0.57Third (to September 30, 2007)

$
27.14

$
25.08

$
0.52Fourth (to December 31, 2007)

$
27.46

$
26.34

$
0.50


At
March 12, 2008, the 5,900,000 Depositary Units outstanding were held by approximately 208 Unitholders of record.

With
respect to the Treasury Obligations, the high and low closing prices per $1,000 face amount for the period from January 1, 2007 to December 31, 2007 were $836.10 and
$738.36, respectively. The closing price on December 31, 2007 was $826.90 per $1,000 face amount.

During
the fourth quarter of 2007, there were no purchases of Units made by or on behalf of the Trust or any "affiliated purchaser" as defined in Rule 10b-18
(a) (3) under the Exchange Act.

Item 6.Selected Financial Data.

|                              |  | Year Ended
|----------------------------- |  | ----------
|
|Royalty Income                |  | $         
|Distributable Income          |  | $         
|Distribution Amount           |  | $         
|Distributable Income Per Unit |  | $         
|Distribution Amount Per Unit  |  | $         
|Total assets at year end      |  | $         

Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operation.

General

The Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Net Profits Interests, to distribute to Unitholders cash
which the Trust receives in respect of the Net Profits Interests and to perform certain administrative functions in respect of the Net Profits Interests and the Depositary Units. The Trust derives
substantially all of its income and cash flows from the Net Profits Interests.

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

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

Over
the remaining life of the Trust, wells may be disposed of from time to time in accordance with the documents governing the Trust.

The
Trust is responsible for paying the Trustee's fees and all legal, accounting, engineering and stock exchange fees, printing costs and other administrative expenses incurred by or at
the direction of the Trustee. The total of all Trustee fees and Trust administrative expenses for 2007 was $621,663, including the Trustee's fee of $108,000. In addition to such expenses, in 2007, the
Trust paid Eastern American an overhead reimbursement of $339,924. The overhead reimbursement increases by 3.5% per year and is payable quarterly.

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

During
2006, the Trust incurred substantially increased fees for professional services relating to the exchange offers made by Ensource Energy Income Fund LP during 2005 and 2006.
Expenses relating to
the Ensource exchange offers incurred by the Trust during 2006 totaled approximately $701,606, including $387,923 for fees and expenses the Trust paid to a financial advisory firm in connection with
its analysis of the Ensource exchange offers. The Trust did not incur any expenses relating to the exchange offers during 2007.

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

29

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Critical Accounting Policies

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

Basis of Accounting:

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

Net Profits Interests in Gas Properties:

The Net Profits Interests in gas properties are periodically assessed to determine whether their net capitalized cost is impaired. The Trust will determine if a
writedown is necessary to its investment in the Net Profits Interests in gas properties to the extent that total capitalized costs, less accumulated amortization, exceed undiscounted future net
revenues attributable to proved gas reserves of the Underlying Properties. The Trust will then provide a writedown to the extent that the net capitalized costs exceed the discounted future net
revenues attributable to proved 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 gas properties is calculated on a units-of-production basis, whereby the Trust's cost basis in the properties is
divided by total Trust proved reserves to derive an amortization rate per reserve unit. Such amortization does not reduce distributable income, rather it is charged directly to Trust Corpus. Revisions
to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.

The
Net Profits Interest impairment test and the determination of amortization rates are dependent on estimates of proved gas reserves attributable to the Trust. Numerous uncertainties
are inherent in estimating reserve volumes and values, including economic and operating conditions, and such estimates are subject to change as additional information becomes available.

Income Taxes:

Tax counsel to the Trust advised 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 income tax purposes and, therefore, would not be subject to taxation at the Trust level. The Trust continues to be tax exempt. Accordingly, no provision for federal or state income
taxes has been made. However, the opinion of tax counsel is not binding on taxing authorities.

Liquidity and Capital Resources

The Trust has no source of liquidity or capital resources 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 administrative expenses and the amount of established reserves, are
distributed currently to the Unitholders.

The
Trust did not have any contractual obligations as of December 31, 2007. At December 31, 2007, the Trust had General and Administrative Expenses Payable of $183,150 and
Distributions Payable of $2,946,825.

30

---





Results of Operations

2007 Compared with 2006

The Trust's Distributable Income was $12,006,605 for the year ended December 31, 2007 as compared to $14,158,872 for the year ended December 31,
2006. This decrease was due to a decrease in Royalty Income for the year ended December 31, 2007 ($14,660,909) as compared to the year ended December 31, 2006 ($17,663,792). The decrease
in Royalty Income was mostly due to a decrease in production of gas attributable to the Net Profits Interests for the year ended December 31, 2007 (1,758 Mmcf) as compared to the year ended
December 31, 2006 (1,847 Mmcf). This decrease was also due to a decrease in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($8.339 per Mcf for the
year ended December 31, 2007 as compared to $9.538 per Mcf for the year ended December 31, 2006). The decline in production is primarily attributable to natural production declines.
Taxes on Production and Property were $1,104,557 for the year ended December 31, 2007 as compared to $1,297,539 for the year ended December 31, 2006. The decrease in taxes is due
directly to the decrease in Royalty Income as discussed above. Trust General and Administrative Expenses were $961,587 for the year ended December 31, 2007 as compared to $1,646,313 for the
year ended December 31, 2006. The decrease in General and Administrative Expenses was due primarily to a decrease in professional fees incurred as a direct result of the exchange offers made by
Ensource Energy Income Fund LP, which were terminated on September 15, 2006.

During
the year ended December 31, 2007, the Trustee refunded $500,000 from the Cash Reserve balance compared to the refunding of $500,000 from the cash reserve for the year ended
December 31, 2006. This Reserve was established to facilitate the payment of vendor invoices on a timely basis. Amortization of Net Profits Interests in Gas Properties was $2,938,058 for the
year ended December 31, 2007 as compared to $2,942,047 for the year ended December 31, 2006. This decrease was due to the decrease in production volumes, offset by an increase in the
depletion rate to $1.6709 for the year ended December 31, 2007 from $1.5932 for the year ended December 31, 2006.

The
average price payable to the Trust for gas production attributable to the Net Profits Interests was $8.339 per Mcf for the year ended December 31, 2007 and $9.538 per Mcf for
the year ended December 31, 2006. The price per Mcf was lower for the year ended December 31, 2007 than for the year ended December 31, 2006 due to a decrease in the average spot
market price for gas delivered at the Henry Hub near Henry, Louisiana ($7.281 per Dth for the year ended December 31, 2007 as compared to $8.371 per Dth for the year ended December 31,
2006).

2006 Compared with 2005

The Trust's Distributable Income was $14,158,872 for the year ended December 31, 2006 as compared to $14,597,387 for the year ended December 31,
2005. This decrease was due to a decrease in Royalty Income for the year ended December 31, 2006 ($17,663,792) as compared to the year ended December 31, 2005 ($18,179,459). The decrease
in Royalty Income was due to a decrease in production of gas attributable to the Net Profits Interests for the year ended December 31, 2006 (1,847 Mmcf) as compared to the year ended
December 31, 2005 (1,956 Mmcf). This decrease was offset by an increase in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($9.538 per Mcf for the year
ended December 31, 2006 as compared to $9.315 per Mcf for the year ended December 31, 2005). The decline in production is primarily attributable to natural production declines. Taxes on
Production and Property were $1,297,539 for the year ended December 31, 2006 as compared to $1,256,330 for the year ended December 31, 2005. The increase in taxes is due to a new West
Virginia tax on the Severance of Natural Resources that is effective for gas produced after November 30, 2005. The additional Severance Tax rate is four and seven-tenths cents per MCF. Trust
General and Administrative Expenses were $1,646,313 for the year ended December 31, 2006 as

31

---



compared
to $1,791,894 for the year ended December 31, 2005. The decrease in General and Administrative Expenses was due primarily to a decrease in professional fees incurred as a direct result
of the exchange offers made by Ensource Energy Income Fund LP, which were terminated on September 15, 2006.

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

The
average price payable to the Trust for gas production attributable to the Net Profits Interests was $9.538 per Mcf for the year ended December 31, 2006 and $9.315 per Mcf for
the year ended
December 31, 2005. The price per Mcf was higher for the year ended December 31, 2006 than for the year ended December 31, 2005 due to an increase in the average spot market price
for gas delivered at the Henry Hub near Henry, Louisiana ($8.371 per Dth for the year ended December 31, 2006 as compared to $8.168 per Dth for the year ended December 31, 2005).

Off-Balance Sheet Arrangements

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

Item 7A.Quantitative and Qualitative Disclosures About Market Risk.

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

Item 8.Financial Statements and Supplementary Data.



|Financial Statements             |                                                                                            |     
|-------------------------------- | ------------------------------------------------------------------------------------------ | ----
|                                 | Report of Independent Registered Public Accounting Firm                                    |     
|                                 | Statements of Assets, Liabilities and Trust Corpus as of December 31, 2007 and 2006        |     
|                                 | Statements of Distributable Income for the years ended December 31, 2007, 2006 and 2005    |     
|                                 | Statements of Changes in Trust Corpus for the years ended December 31, 2007, 2006 and 2005 |     
|Notes to Financial Statements    |                                                                                            | F-6 
|Supplemental Reserve Information |                                                                                            | F-11

32

---



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

None.

Item 9A.Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or
submits under the Securities Exchange Act of
1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and
procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by several parties, including without limitation, the working interest owner,
Eastern American Energy Corporation ("Eastern American"), and the independent reserve engineer to The Bank of New York Trust Company, N.A., as Trustee of the Trust, and its employees who participate
in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure. In addition, the Trustee is required by the Trust Agreement to engage and has
engaged an independent registered public accounting firm to review the quarterly financial statements of the Trust and audit the annual financial statements of the Trust, which includes financial data
provided by Eastern American.

As
of December 31, 2007, the Trustee carried out an evaluation of the Trustee's disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded
that the disclosure controls and procedures are effective.

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



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

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

The
Trustee does not expect that the Trustee's disclosure controls and procedures or the Trustee's internal control over financial reporting will prevent all errors and all fraud.
Further, the design of disclosure controls and procedures and internal control over financial reporting must reflect the fact that there are resource constraints, and the benefits of controls must be
considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud,
if any, have been detected.

33

---



Changes in Internal Control Over Financial Reporting

In connection with the evaluation by the Trustee of changes in internal control over financial reporting of the Trust, no change in the Trust's internal control
over financial reporting was identified that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting.

Trustee's Report on Internal Control over Financial Reporting

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in
Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust's internal control over
financial reporting based on the criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on the Trustee's evaluation under the framework inInternal Control-Integrated Framework, the Trustee concluded that the
Trust's internal control over financial reporting was effective as of December 31, 2007. The effectiveness of the Trust's internal control over financial reporting as of December 31,
2007 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

A
registrant's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A registrant's internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrant s assets that could have a material effect on the
financial statements.

Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Item 9B.Other Information.

None.

PART III

Item 10.Directors, Executive Officers and Corporate Governance.

The Trust has no directors or executive officers. The Trustee is a corporate trustee which may be removed by the affirmative vote of holders of a majority of the
Trust Units then outstanding at a meeting of the Unitholders of the Trust at which a quorum is present. The Trust is not required to and does not hold annual meetings of the Unitholders.

The
Trust also does not have an audit committee. The Trust has not adopted a code of ethics, as the Trust has no directors, officers, or employees. The Trust has not adopted a process by
which Unitholders may communicate with board members, as the Trust has no board members or persons fulfilling a similar function. Unitholders may contact the Trustee at the following address: The Bank
of

34

---



New
York Trust Company, N.A., Trustee of Eastern American Natural Gas Trust, Global Corporate Trust, 919 Congress Avenue Suite 500, Austin, Texas 78701.

Item 11.Executive Compensation.

The Trust has no officers or directors, and is administered by the Trustee. For the year ended December 31, 2007 and December 31, 2006, The Bank of
New York Trust Company, N.A., as Trustee, received $108,000 and for the year ended December 31, 2005, JPMorgan Chase Bank, N.A., as Trustee, received $108,000 annually, as Trustee fees and
$513,663, $1,209,881 and $1,366,570, respectively, as reimbursement of legal, accounting, and other professional expenses for such services. Effective January 1, 2005, the annual Trustee fee
was fixed at $108,000.

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



Based
on filings with the Securities and Exchange Commission, the Trust is not aware of any Unitholder owning beneficially more than 5% of the Units as of December 31, 2007 except
as follows:

Name and Address

Units Held

Percentage of OutstandingRiver Road Asset Management, LLC
462 S. 4th Street, Ste 1600
Louisville, KY 40202

344,577
(1)
5.8
%


---

Not
applicable.



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



The
Trust has no equity compensation plans.

Item 13.Certain Relationships and Related Transactions, and Director Independence.

The
Trust has no directors.

Item 14.Principal Accounting Fees and Services.

Audit Fees

The fees PricewaterhouseCoopers LLP billed the Trust for each of the last two fiscal years for professional services rendered in connection with the audits
of the Trust's annual financial statements and review of the Trust quarterly interim financial statements were $196,251 in 2007 and $193,516 in 2006.

35

---



Audit-Related Fees

PricewaterhouseCoopers LLP did not bill the Trust any additional fees in the last two fiscal years for assurance and related services that are reasonably
related to the performance of the audit or review of the Trust's financial statements.

Tax Fees

The fees, including expenses, PricewaterhouseCoopers LLP billed the Trust for each of the last two fiscal years for compliance, tax advice or planning were
$100,000 in 2007 and $128,000 in 2006.

All Other Fees

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

Pre-Approval Policies

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

PART IV

Item 15.Exhibits, Financial Statement Schedules.

|Reports              |                                                                        | 
|-------------------- | ---------------------------------------------------------------------- | 
|                     | Reserve Report of Ryder Scott Company, Independent Petroleum Engineers | 
|Financial Statements |                                                                        | 

The
following financial statements are included in this Annual Report on Form 10-K on the pages indicated:

| | Report of Independent Registered Public Accounting Firm                                    |  | F-2 
| | ------------------------------------------------------------------------------------------ |  | ----
| | Statements of Assets, Liabilities and Trust Corpus as of December 31, 2007 and 2006        |  | F-3 
| | Statements of Distributable Income for the years ended December 31, 2007, 2006 and 2005    |  | F-4 
| | Statements of Changes in Trust Corpus for the years ended December 31, 2007, 2006 and 2005 |  | F-5 
| | Notes to Financial Statements                                                              |  | F-6 
| | Supplemental Information                                                                   |  | F-11

Schedules

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

Exhibits

Except
as otherwise indicated below, all exhibits, except Exhibit 31 and Exhibit 32, are incorporated herein by reference to the indicated exhibits to filings previously
made by the registrant with the Securities and Exchange Commission. All references are to the registrant's Registration

36

---



Statement
on Form S-1, Registration No. 33-56336, except for Exhibit 3.1, which is incorporated by reference to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1994.

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

37

---





SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized on this 14th day of March, 2008.

| |  | EASTERN AMERICAN NATURAL GAS TRUST
| |  | ----------------------------------
| |  | By:                               
| |  | By:                               
| |  | Name:                             
| |  | Title:                            

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

38

---



[Ryder Scott Company, Independent Petroleum Engineers Letterhead]

February 1,
2008

Eastern
American Natural Gas Trust
The Bank of New York Trust Company, N.A.
919 Congress Avenue
Suite 500
Austin, Texas 78701

Gentlemen:

Pursuant
to your request, we present below estimates of the net proved reserves attributable to the interests of the Eastern American Natural Gas Trust (Trust) as of December 31,
2007. The Trust is a grantor trust formed to hold interests in certain domestic oil and gas properties owned by Eastern American Energy Corporation (EAEC), a wholly owned subsidiary of Energy
Corporation of America (ECA). The interests conveyed to the Trust consist of a net profits interest derived from working and royalty interests in numerous properties. The Net Profits Interest consists
of (1) a life-of-properties interest ("Royalty NPI") and (2) a term interest ("Term NPI"). The properties included in the Trust are located in the states of
Pennsylvania and West Virginia.

The
estimated reserve quantities and future income quantities presented in this report are related to a large extent to hydrocarbon prices. Hydrocarbon prices in effect at
December 31, 2007 were used in the preparation of this report as required by Securities and Exchange Commission (SEC) and Financial Accounting Standards Bulletin No. 69 (FASB 69)
guidelines; however, actual future prices may vary significantly from December 31, 2007 prices for reasons discussed in more detail in other sections of this report. Therefore, quantities of
reserves actually recovered and quantities of income actually received may differ significantly from the estimated quantities presented in this report.

As of December 31, 2007Gas

Estimated Future Net Cash Inflows

Present Value At 10%(MMCF)

(M$)

(M$)Proved Net DevelopedRoyalty NPI

10,012

82,498

33,727Term NPI

3,825

31,520

24,787Total

13,837

114,018

58,514


Reserve
quantities are calculated differently for a Net Profits Interest because such interests do not entitle the Trust to a specific quantity of oil or gas but to 90 percent of
the Net Proceeds derived therefrom beginning on January 1, 2008 for natural gas. Accordingly, there is no precise method of allocating estimates of the quantities of proved reserves
attributable to the Net Profits Interest between the interest held by the Trust and the interests to be retained by EAEC. For purposes of this presentation, the proved reserves attributable to the Net
Profits Interests have been proportionately reduced to reflect the future estimated costs and expenses deducted in the calculation of Net Proceeds with respect to the Net Profits Interests.
Accordingly, the reserves presented for the Net Profits Interest reflect quantities of gas that are free of future costs or expenses based on the price and cost assumptions utilized in this report.
The allocation of proved reserves of the Net Profits Interest between the Trust and EAEC will vary in the future as relative estimates of future gross revenues and future net incomes vary.
Furthermore, EAEC requested that for purposes of our report the "Royalty NPI" be calculated beyond the Liquidation Date of May 15, 2013, even though by the terms of the Trust Agreement the
Royalty NPI will be sold by the Trustee on or about this date and a liquidating

A-1

---



distribution
of the sales proceeds from such sale would be made to holders of Trust Units. The Trust Agreement provides that the "Term NPI" entitles the Trust to receive the net proceeds from the gas
produced from the properties burdened by the "Term NPI" until the earlier of May 15, 2013 or until such time as 41,683 MMCF of gas has been produced. For purposes of this report, the "Term NPI"
was limited to May 15, 2013.

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

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

Proved reservesof crude oil, natural gas, or natural gas liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions. Reservoirs are considered proved if economic producibility is supported by actual
production or formation tests. In certain instances, proved reserves may be assigned on the basis of a combination of core analysis and electrical and other type logs which indicate the reservoirs are
analogous to reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (1) that
portion delineated by drilling and defined by fluid contacts, if any, and (2) the adjoining portions not yet drilled that can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Proved
reserves are estimates of hydrocarbons to be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional data becomes available. Proved natural gas reserves
consist of non-associated, associated and dissolved gas. An appropriate reduction in gas reserves has been made for the expected removal of natural gas liquids, for lease and plant fuel,
and for the exclusion of non-hydrocarbon gases if they occur in significant quantities.

Reserves
that can be produced economically through the application of improved recovery techniques are included in the proved classification when these qualifications are met:
(1) successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based, and
(2) it is reasonably certain the project will proceed. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery
from a reservoir, including (1) pressure maintenance, (2) cycling, and (3) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods
of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids.

Estimates
of proved reserves do not include crude oil, natural gas, or natural gas liquids being held in underground or surface storage.



A-2

---





In
accordance with the requirements of FASB 69, estimates of future cash inflows, future costs and future net cash inflows before income tax, as well as estimated reserve
quantities, as of December 31, 2007 from this report are presented in the following table:

As of December 31, 2007Royalty
NPI

Term
NPI

TotalsTotal ProvedFuture Cash Inflows (M$)

82,498

31,520

114,018Future CostsProduction (M$)

0

0

0Development (M$)

0

0

0Total Costs (M$)

0

0

0Future Net Cash Inflows Before Income Tax (M$)

82,498

31,520

114,018Present Value at 10% Before Income Tax (M$)

33,727

24,787

58,514


|
|

As of December 31, 2007Royalty
NPI

Term
NPI

TotalsProved Net Developed ReservesGas (MMCF)

10,012

3,825

13,837Proved Net Undeveloped ReservesGas (MMCF)

0

0

0Total Proved Net ReservesGas (MMCF)

10,012

3,825

13,837


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

EAEC
furnished us gas prices in effect at December 31, 2007 and with its forecasts of future gas prices which take into account Securities and Exchange Commission guidelines,
current market prices, contract prices and fixed and determinable price escalations where applicable. In accordance with Securities and Exchange Commission guidelines, the future gas prices used in
this report make no allowances for future gas price increases or decreases which may occur as a result of inflation nor do they account for seasonal variations in gas prices which are likely to cause
future yearly average gas prices to be somewhat higher than December gas prices. In those cases where contract market-out has occurred, the current market price was held constant to
depletion of the reserves. In those cases where market-out has not occurred, contract gas prices including fixed and determinable escalations, exclusive

A-3

---



of
inflation adjustments, were used until the contract expired and then reduced to the current market price for similar gas in the area and held at this reduced price to depletion of the reserves.

This
report utilized the terms of the gas contract between Eastern Marketing Corporation (a wholly owned subsidiary of EAEC) and the Trust. Gas price is to be determined by a weighted
price consisting of two components during a primary term defined to begin on January 1, 1993 and end December 31, 1999. The first component is the "Fixed" price which has been defined as
$2.66 per Mcf beginning January 1, 1993. This price escalates 5 percent per year on January 1 of each year during the primary term beginning in 1994. The second component is the
"Variable" price which for any quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu, plus $0.30 per MMBtu, multiplied by 110 percent to effect a Btu adjustment. The Henry
Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter as the average price of the three months in such quarter where each month's price is equal to the average
of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in theWall Street Journal, for such
contracts which expired in each of the five months prior to each month of such quarter, (ii) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported in the Wall Street Journal, for such contracts which expire during such month and (iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures
Contracts for such month, as reported in theWall Street Journal, for such contracts which expire in each of the six months following such month. A
Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to be delivered to the Henry Hub which is traded on the New York Mercantile Exchange. The weighted average price is
determined by giving the "Fixed" price a 662/3 percent weighting and the variable price a 331/3 percent weighting.

Since
the primary term is complete, the purchase price under the gas contract will be equal to the "Variable" price. EAEC computed the "Variable" price under the gas contract as of
December 31, 2007 as $8.240 per Mcf, utilizing $7.191 as the Henry Hub Average Spot Price computed in accordance with the gas contract.

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

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

Our
reserve estimates are based upon a study of the properties in which the Trust has interests; however, we have not made any field examination of the properties. No consideration was
given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, in any, caused by past operating
practices. EAEC informed us that it has furnished us all of the accounts, records, geological and engineering data and reports and other data as were required for our investigation. The ownership
interests, terms of the Trust, prices, taxes, and other factual data furnished to us in connection with our investigation were accepted as represented. The estimates presented in this report are based
on data available through September, 2007.

At
the time of formation of the Trust, EAEC assigned The Trust an interest in 65 undeveloped locations. During the period 1993 through 1998, EAEC has completed it's drilling obligation.
A total of 59 wells were drilled over this period. Two wells were not drilled due to title failure and four wells were not drilled due to short spacing. Reserves and projections of future production
are included for the four locations which were not drilled due to short spacing.

A-4

---



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

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

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

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

Estimated
Net Reserve Data
Certain Combined Leasehold Interests of
Eastern America Energy Corporation
And The Trust
As of December 31, 2007SEC Parameters

ProvedTotal ProvedDeveloped

UndevelopedNet Remaining ReservesGas-MMCF

27,591

0

27,591


The
estimated future net income associated with the foregoing volumes and the 10 percent discounted estimated future net income was $189,080,533 and $76,427,115, respectively.
This evaluation utilizes the same price and cost assumptions that were utilized for evaluating the Trust and discussed earlier in the letter. The properties which are included in the "Term NPI" were
allowed to run for their full economic life in this evaluation.

Neither
Ryder Scott Company nor any of its employees has any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our
estimates of reserves and future cash inflows for the subject properties.

| | Very truly yours,                                  
| | ---------------------------------------------------
| | RYDER SCOTT COMPANY, L.P.                          
| | Larry T. Nelms P. E. Managing Senior Vice President

LTN:ph

A-5

---





EASTERN AMERICAN NATURAL GAS TRUST

---

FINANCIAL STATEMENTS

as
of December 31, 2007 and 2006
and for the years ended
December 31, 2007, 2006 and 2005

---





Report of Independent Registered Public Accounting Firm

To the Unit Holders of Eastern American Natural Gas Trust and The Bank of New York Trust Company, N.A., Trustee

We
have audited the accompanying statements of assets, liabilities and trust corpus of Eastern American Natural Gas Trust (the "Trust") as of December 31, 2007 and 2006, and the
related statements of distributable income, and statements of changes in trust corpus for each of the three years in the period ended December 31, 2007. We also have audited the Trust's
internal control over financial reporting as of December 31, 2007, based on criteria established inInternal ControlIntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trustee is responsible for these financial statements, for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the Trustee's Report on Internal Control over Financial Reporting
appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Trust's internal control over financial reporting based on our integrated audits.

We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our
opinions.

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

A
trust's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A trust's internal control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In
our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Trust at December 31, 2007 and 2006, and the
distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2007, on the basis of accounting described in Note 2. Also in our opinion,
the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established inInternal
ControlIntegrated Frameworkissued by COSO.

/s/
PricewaterhouseCoopers LLP

Pittsburgh,
Pennsylvania
March 14, 2008

F-2

---





EASTERN AMERICAN NATURAL GAS TRUST  STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS  as of December 31, 2007 and 2006

|                              |                                                           | 2007                               |            | 2006        |           
|----------------------------- | --------------------------------------------------------- | ---------------------------------- | ---------- | ----------- | ----------
|Assets:                       |                                                           |                                    |            |             |           
|                              | Cash                                                      |                                    | $          | 197,972     |           
|                              | Net Proceeds Receivable                                   |                                    |            | 3,132,003   |           
|                              | Net Profits Interests in Gas Properties                   |                                    |            | 93,162,180  |           
|                              | Accumulated Amortization                                  |                                    |            | (71,539,020 | )         
|                              |                                                           |                                    |            |             |           
|                              |                                                           |                                    | 21,623,160 |             |           
|                              |                                                           | Total Assets                       |            | $           | 24,953,135
|                              |                                                           |                                    |            |             |           
|Liabilities and Trust Corpus: |                                                           |                                    |            |             |           
|                              | Trust General and Administrative Expenses Payable         |                                    | $          | 183,150     |           
|                              | Distributions Payable to Unitholders                      |                                    |            | 2,946,825   |           
|                              | Trust Corpus (5,900,000 units authorized and outstanding) |                                    |            | 21,823,160  |           
|                              |                                                           |                                    |            |             |           
|                              |                                                           | Total Liabilities and Trust Corpus |            | $           | 24,953,135
|                              |                                                           |                                    |            |             |           

The accompanying notes are an integral part of these financial statements.

F-3

---



EASTERN AMERICAN NATURAL GAS TRUST  STATEMENTS OF DISTRIBUTABLE INCOME  for the years ended  December 31, 2007, 2006 and 2005

|                                                                           |                                  | 2007                     |            | 2006      |            | 2005       |          
|-------------------------------------------------------------------------- | -------------------------------- | ------------------------ | ---------- | --------- | ---------- | ---------- | ---------
|Royalty Income                                                             |                                  | $                        | 14,660,909 |           | $          | 17,663,792 |          
|                                                                           |                                  |                          |            |           |            |            |          
|Operating Expenses:                                                        |                                  |                          |            |           |            |            |          
|                                                                           | Taxes on Production and Property |                          |            | 1,104,557 |            |            | 1,297,539
|                                                                           | Operating Cost Charges           |                          |            | 588,160   |            |            | 561,068  
|                                                                           |                                  |                          |            |           |            |            |          
|                                                                           |                                  | Total Operating Expenses |            |           | 1,692,717  |            |          
|                                                                           |                                  |                          |            |           |            |            |          
|Net Proceeds to the Trust                                                  |                                  |                          | 12,968,192 |           |            | 15,805,185 |          
|General and Administrative Expenses                                        |                                  |                          | 961,587    |           |            | 1,646,313  |          
|Interest Income                                                            |                                  |                          |           |           |            |           |          
|                                                                           |                                  |                          |            |           |            |            |          
|                                                                           |                                  | Distributable Income     |            |           | 12,006,605 |            |          
|Cash Reserve Refunded (Withheld)                                           |                                  |                          | 500,000    |           |            | 500,000    |          
|                                                                           |                                  |                          |            |           |            |            |          
|                                                                           |                                  | Distribution Amount      |            | $         | 12,506,605 |            | $        
|                                                                           |                                  |                          |            |           |            |            |          
|Distributable Income Per Unit (5,900,000 units authorized and outstanding) |                                  | $                        | 2.0350     |           | $          | 2.3998     |          
|                                                                           |                                  |                          |            |           |            |            |          
|Distribution Amount Per Unit (5,900,000 units authorized and outstanding)  |                                  | $                        | 2.1198     |           | $          | 2.4846     |          
|                                                                           |                                  |                          |            |           |            |            |          

The accompanying notes are an integral part of these financial statements.

F-4

---





EASTERN AMERICAN NATURAL GAS TRUST  STATEMENTS OF CHANGES IN TRUST CORPUS  for the years ended  December 31, 2007, 2006 and 2005

|                                                        |  | 2007 |             | 2006 |   | 2005        |  
|------------------------------------------------------- |  | ---- | ----------- | ---- | - | ----------- | -
|Trust Corpus, Beginning of Year                         |  | $    | 25,261,218  |      | $ | 28,703,265  |  
|Distributable Income                                    |  |      | 12,006,605  |      |   | 14,158,872  |  
|Distributions Paid or Payable to Unitholders            |  |      | (12,506,605 | )    |   | (14,658,872 | )
|Amortization of Net Profits Interests in Gas Properties |  |      | (2,938,058  | )    |   | (2,942,047  | )
|                                                        |  |      |             |      |   |             |  
|Trust Corpus, End of Year                               |  | $    | 21,823,160  |      | $ | 25,261,218  |  
|                                                        |  |      |             |      |   |             |  

The accompanying notes are an integral part of these financial statements.

F-5

---





EASTERN AMERICAN NATURAL GAS TRUST        NOTES TO FINANCIAL STATEMENTS

1.Organization of the Trust:

The Eastern American Natural Gas Trust (the "Trust") was formed under the Delaware Business Trust Act pursuant to a Trust Agreement (the "Trust Agreement") among
Eastern American Energy Corporation ("Eastern American"), as grantor, Bank of Montreal Trust Company, as 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 of Montreal Trust Company / Harris Trust, and consequently, The Bank of New York served as trustee of the
Trust. On November 20, 2004, the holders of a majority of the Trust Units voting at a special meeting approved the resignation of The Bank of New York as trustee and depository of the Trust and
the appointment of JPMorgan
Chase Bank, N.A. as successor trustee of the Trust, effective as of January 1, 2005. Effective October 2, 2006, The Bank of New York Trust Company, N. A. replaced JPMorgan Chase Bank,
N.A. as trustee in connection with the sale by JPMorgan Chase Bank of substantially all of its corporate trust business to The Bank of New York. Consequently, references herein to the "Trustee" mean
Bank of Montreal Trust Company until May 8, 2000; The Bank of New York as successor Trustee from May 8, 2000 through December 31, 2004; JPMorgan Chase Bank, N.A. as successor
trustee, from January 1, 2005 through October 2, 2006; and The Bank of New York, N.A. as successor trustee, effective as of October 2, 2006. The transfer agent for the Trust is
Bondholder Communications, an affiliate of The Bank of New York Trust Company, N.A.

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

The
Royalty NPI is not limited in term or amount. Under the Trust Agreement, the Trustee is directed to sell all remaining Royalty NPI after May 15, 2012 and prior to
May 15, 2013, and net proceeds from selling such Royalty NPI will be distributed to Unitholders on the first quarterly payment date following the receipt of such proceeds by the Trust. The Term
NPI will expire on the earlier of May 15, 2013 or such time as 41,683 MMcf of gas has been produced which is attributable to Eastern American's net revenue interests in the properties burdened
by the Term NPI. As of December 31, 2007, 25,419 MMcf of such gas had been produced.

Eastern
American can sell the Underlying Properties, subject to and burdened by the Net Profits Interests, without the consent of the Trustee or the Unitholders. In limited
circumstances, Eastern American also can transfer the Underlying Properties and require the Trust to release the NPI burdening that property, without the consent of the Trustee or Unitholders, subject
to payment to the Trust of the fair value of the interest released. In addition, any abandonment of a well included in the Underlying Properties or the Development Wells will extinguish that portion
of the Net Profits Interests that relate to such well.

Four
(4) of the remaining six (6) development wells were closely offset by third parties. Since the wells drilled by the third parties were within 1,000 feet of these
development wells, Eastern American had a disagreement with the Trust over Eastern American's obligation to drill these closely offset development wells. The Trust agreed that, in lieu of drilling
these closely offset development wells Eastern American 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 the projected volumes of the wells as if they had been drilled. These volumes have been estimated by the Ryder Scott Company.

F-6

---



EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

1.Organization of the Trust:(Continued)

The
two (2) remaining development wells were not drilled because Eastern American was unable to cure various title defects associated with these wells. Eastern American advised
the Trust that it made a diligent effort to cure title but was unsuccessful. In West Virginia, an oil and gas well cannot be drilled unless a full and complete 100% leasehold interest is first
obtained. Drilling an oil and gas well without obtaining the entire leasehold estate would expose the oil and gas operator and the Trust to a possible suit for trespass. Pursuant to the Term Net
Profits Interest Conveyance, if the state of title to the drill site to any development well renders such property undrillable in the good faith opinion of Eastern American under the Reasonably
Prudent Operator Standard then such drill site(s) shall be construed as a development well(s). Consequently, Eastern American has fulfilled its commitment to the 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 public offering price of $20.50 per depositary unit. Each depositary unit consists of
beneficial ownership of one unit of beneficial interest ("Trust Unit") in the Trust and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon United States Treasury
Obligation ("Treasury Obligation") maturing on May 15, 2013. Of the net proceeds from such offering, $27,787,820 was used to purchase $118,000,000 in face amount of Treasury Obligations and
$93,162,180 was paid to Eastern American in consideration for the conveyance of the Net Profits Interests to the Trust. The Trust acquired the Net Profits Interests effective as of January 1,
1993. The Treasury Obligations are directly owned by the Unitholders and are not part of the Trust Corpus. The Treasury Obligations are on deposit with the Trustee pursuant to the Deposit Agreement.

The
Net Profits Interests are passive in nature, and neither the Trustee nor the Delaware Trustee has management control or authority over, nor any responsibility relating to, the
operation of the properties subject to the Net Profits Interests. The Trust Agreement provides, among other things, that the Trust shall not engage in any business or commercial activity or acquire
any asset other than the Net Profits Interests initially conveyed to the Trust; the Trustee may establish a reserve for payment of any liability which is contingent, uncertain in amount or that is not
currently due and payable; the Trustee is authorized to borrow funds required to pay liabilities of the Trust, provided that such borrowings are repaid in full prior to further distributions to
Unitholders; and the Trustee will make quarterly cash distributions to Unitholders from funds of the Trust.

2.Significant Accounting Policies:

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

Basis of Accounting:

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

Most
accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. generally accepted accounting principles. Because the trust's financial
statements are prepared on a comprehensive basis of accounting other than U.S. generally accepted accounting

F-7

---



EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

2.Significant Accounting Policies:(Continued)

principles,
as described above, most accounting pronouncements are not applicable to the trust's financial statements.

Cash:

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

Net Profits Interests in Gas Properties:

The Net Profits Interests in gas properties are periodically assessed to determine whether their net capitalized cost is impaired. The Trust will determine if a
writedown is necessary to its investment in the Net Profits Interests in gas properties to the extent that total capitalized costs, less accumulated amortization, exceed undiscounted future net
revenues attributable to proved gas reserves of the Underlying Properties. The Trust will then provide a writedown to the extent that the net capitalized costs exceed the discounted future net
revenues attributable to proved gas reserves of the Underlying Properties. Any such writedown would not reduce Distributable Income, although it would reduce Trust Corpus.

Significant
dispositions or abandonment of the Underlying Properties are charged to Net Profits Interests and the Trust Corpus.

Amortization
of the Net Profits Interests in gas properties is calculated on a units-of-production basis, whereby the Trust's cost basis in the properties is
divided by total Trust proved reserves to derive an amortization rate per reserve unit. Such amortization does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Revisions
to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.

The
conveyance of the Royalty and Term Interests to the Trust was accounted for as a purchase transaction. The $93,162,180 reflected in the Statements of Assets, Liabilities and Trust
Corpus as Net Profits Interests in Gas Properties represents 5,900,000 Trust Units valued at $20.50 per depository unit less the $27,787,820 paid for Treasury obligations. The carrying value of the
Trust's investment in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.

Revenues and Expenses:

The Trust serves as a pass-through entity, with items of depletion, interest income and expense, and income tax attributes being based upon the status
and election of the Unitholders. Thus, the Statements of Distributable Income purport to show Distributable Income, defined as Trust income available for distribution to Unitholders before application
of those Unitholders' additional expenses, if any, for depletion, interest income and expense, and income taxes.

The
Trust uses the accrual basis to recognize revenue, with royalty income recorded as reserves are extracted from the Underlying Properties and sold. Expenses are also recognized on an
accrual basis. Operating expenses which include Taxes on Property and Production and Operating Cost Charges are recognized as incurred pursuant to the Conveyances on a per well production basis. The
payment provisions of the Gas Purchase Contract between the Trust and Eastern Marketing Corporation ("Eastern Marketing"), a wholly owned subsidiary of Eastern American, require payment with respect

F-8

---



EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

2.Significant Accounting Policies:(Continued)

to
gas production for a calendar quarter to be made to the Trust on or before the tenth day of the third month following such quarter.

Use of Estimates in the Preparation of Financial Statements:

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

Segment Information:

In 1998, the Trust adopted Statement of Financial Accounting Standards No. 131, "Disclosure about Segments of an Enterprise and Related Information." The
Trust's sole activity is earning royalty income from gas properties and, consequently, the Trust has only one operating segment, net profits interests in gas properties. Substantially all of the
Trust's net profits interests are located in the Appalachian region.

3.Income Taxes:

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

The
Unitholders are considered, for income tax purposes, to own the Trust's income and principal as though no trust were in existence. Thus, the taxable year for reporting a Unitholder's
share of the Trust income, expense and credits are controlled by the Unitholder's taxable year and method of accounting, not the taxable year and method of accounting employed by the Trust.

4.Distributions to Unitholders:

The Trustee determines for each quarter the amount available for distribution to the Unitholders. Such amount 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 each calendar quarter ending prior to the dissolution of the Trust, from the Net Profits Interests then held
by the Trust attributable to production during such quarter, plus, with certain exceptions, any other cash receipts of the Trust during such quarter, over the liabilities of the Trust paid during such
quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established at the discretion of the Trustee for the payment of contingent or future
obligations of the Trust. Cash received by the Trustee in a particular quarter from the Net Profits Interests will reflect actual gas production for a portion of such quarter and a production estimate
for the remainder of such quarter, such estimate to be adjusted to actual production in the following quarter. In accordance with the Trust Agreement and Delaware law, Unitholders should be shielded
from direct liability for any environmental liabilities. However, costs and expenses incurred by Eastern American for certain Capital Costs associated with environmental liabilities arising after the
effective date of the Conveyances would reduce Net Proceeds, and would therefore be borne, in part, by the Unitholders.

F-9

---



EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

4.Distributions to Unitholders:(Continued)

Net
Proceeds Receivable included in the Statements of Assets, Liabilities and Trust Corpus as of December 31, 2007 are expected to be received by the Trust and distributed to the
Unitholders on March 14, 2008. The December 31, 2006 Net Proceeds Receivable were received and distributed by the Trust on March 15, 2007.

5.Related Party Transactions:

The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees, printing costs and other administrative expenses incurred at the
direction of the Trustee. The total of all Trustee fees and Trust administrative expenses was $621,663 for the year ended December 31, 2007, $1,317,881 for the year ended December 31,
2006, and $1,474,570 for the year ended December 31, 2005. In accordance with the Trust Agreement, the Trustee pays Eastern American an annual fee which increases by 3.5% per year, payable
quarterly, to reimburse Eastern American for overhead expenses. The initial fee at the inception of the Trust was $210,000. The Trustee paid Eastern American $339,924, $328,432 and $317,324 for
overhead expenses for 2007, 2006 and 2005 respectively. Operating Cost Charges included in the Statements of Distributable Income are paid to Eastern American.

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

Pursuant
to the Gas Purchase Contract, Eastern Marketing is obligated to purchase such gas production 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 the Primary Term, which ended December 31, 1999. Effective January 1, 2000, Eastern Marketing is obligated to purchase
such gas production at a purchase price per Mcf equal to the Index Price for gas produced in any quarter after the Primary Term.

The
Index Price for any quarter subsequent to the Primary Term, which expired December 31, 1999, is determined solely by reference to the Variable Price component. The Variable
Price for any quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. The Henry Hub Average
Spot Price is defined as the price per MMBtu determined for any calendar quarter equal to the price obtained with respect to each of the three months in such quarter, in the manner specified below,
and then taking the average of the prices determined for each of such three months. The price determined for any month of such quarter is equal to the average of (i) the final settlement prices
per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported inThe Wall Street Journal,for such 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 inThe Wall Street
Journal,for such contracts which expire during such month and (iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures Contracts determined as of the
contract settlement date for such month, as reported inThe Wall Street Journal,for such contracts which expire in each of the six months following
such month. A Henry Hub
Gas Futures Contract is defined as a gas futures contract for gas to be delivered to the Henry Hub which is traded on the New York Mercantile Exchange.

Under
a standby performance agreement, Eastern American has agreed to make payments under the Gas Purchase Contract to the extent such payments are not made by Eastern Marketing.

F-10

---



Supplemental Reserve Information (Unaudited):

Information regarding estimates of the proved gas reserves attributable to the Trust are based on reports prepared by independent petroleum engineering
consultants. Such estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission. Accordingly, the estimates were based on existing economic and operating
conditions. Numerous uncertainties are inherent in estimating reserve volumes and values and such estimates are subject to change as additional information becomes available.

The
reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.

The
standardized measure of discounted future net cash flows was determined based on reserve estimates prepared by the independent petroleum engineering consultants. Fixed gas prices
were used during the Primary Term, which ended December 31, 1999. The gas prices used thereafter are based solely on the fourth quarter Variable Price component.

The
reserves and revenue values for the Underlying Properties transferred to the Trust were estimated from projections of reserves and revenue values attributable to the combined Eastern
American and Trust interests in these properties. Reserve quantities are calculated differently for the Net Profits Interests because such interests do not entitle the Trust to a specific quantity of
gas but to 90% of the Net Proceeds derived therefrom. Accordingly, there is no precise method of allocating estimates of the quantities of proved reserves between those held by the Trust and the
interests to be retained by Eastern American. For purposes of this presentation, the proved reserves attributable to the Net Profits Interests have been proportionately reduced to reflect the future
estimated costs and expenses deducted in the calculation of Net Proceeds with respect to the Net Profits Interests. The reserves presented for the Net Profits Interests reflect quantities of gas that
are free of future costs or expenses. The allocation of proved reserves between the Trust and Eastern American will vary in the future as relative estimates of future gross revenues and future costs
and expenses vary.

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

The
following table reconciles the change in proved reserves attributable to the Trust's share of the Net Profits Interests ("NPI") from January 1, 2005 to December 31,
2007:

Royalty NPI

Term NPI

Total NPI(MMcf)

(MMcf)

(MMcf)Balance, January 1, 2005

11,456

6,702

18,158Production

(849
)
(1,107
)
(1,956
)Revisions of previous estimates

659

402

1,061Balance, December 31, 2005

11,266

5,997

17,263Production

(788
)
(1,059
)
(1,847
)Revisions of previous estimates

(593
)
(124
)
(717
)Balance, December 31, 2006

9,885

4,814

14,699Production

(774
)
(984
)
(1,758
)Revisions of previous estimates

901

(5
)
896Balance, December 31, 2007

10,012

3,825

13,837


F-11

---



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

Royalty NPI

Term NPI

Total NPI(MMcf)

(MMcf)

(MMcf)December 31, 2005

11,266

5,997

17,263December 31, 2006

9,885

4,814

14,699December 31, 2007

10,012

3,825

13,837


Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:

The
following is the standardized measure of discounted future net cash flows as of December 31, 2007 (in thousands):

Royalty NPI

Term
NPI

Total
NPIFuture cash inflows

$
99,875

$
35,706

$
135,581Future production taxes


(4,548
)

(1,475
)

(6,023
)Future production costs


(12,829
)

(2,711
)

(15,540
)Future net cash inflows


82,498


31,520


114,01810% discount factor


(48,771
)

(6,733
)

(55,504
)Standardized measure of discounted future net cash flows

$
33,727

$
24,787

$
58,514


The
following is the standardized measure of discounted future net cash flows as of December 31, 2006 (in thousands):

Royalty NPI

Term
NPI

Total
NPIFuture cash inflows

$
96,482

$
43,880

$
140,362Future production taxes


(4,395
)

(1,762
)

(6,157
)Future production costs


(12,060
)

(3,411
)

(15,201
)Future net cash inflows


80,027


38,977


119,00410% discount factor


(46,248
)

(9,496
)

(55,744
)Standardized measure of discounted future net cash flows

$
33,779

$
29,481

$
63,260


F-12

---



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

Royalty NPI

Term
NPI

Total
NPIFuture cash inflows

$
163,809

$
83,267

$
247,076Future production taxes


(7,104
)

(3,146
)

(10,250
)Future production costs


(14,781
)

(4,581
)

(19,362
)Future net cash inflows


141,924


75,540


217,46410% discount factor


(82,646
)

(20,548
)

(101,194
)Standardized measure of discounted future net cash flows

$
59,278

$
54,992

$
114,270


Changes
in Standardized Measure of Discounted Future Net Cash Flows:

The
following schedule reconciles the changes during 2005, 2006 and 2007 in the standardized measure of discounted future net cash flows relating to proved reserves (in thousands):

Royalty NPI

Term
NPI

Total
NPIStandardized measure, January 1, 2005

$
38,406

$
37,790

$
76,196Net proceeds to the Trust


(10,696
)

(5,693
)

(16,389
)Revisions of previous estimates


4,362


2,661


7,023Accretion of discount


3,841


3,779


7,620Net change in price and production costs


25,240


11,848


37,088Other


(1,875
)

4,607


2,731Standardized measure, December 31, 2005

$
59,278

$
54,992

$
114,270Net proceeds to the Trust


(10,629
)

(5,176
)

(15,805
)Revisions of previous estimates


(2,553
)

(534
)

(3,087
)Accretion of discount


5,928


5,499


11,427Net change in price and production costs


(24,264
)

(11,435
)

(35,699
)Other


6,019


(13,865
)

(7,846
)Standardized measure, December 31, 2006

$
33,779

$
29,481

$
63,260Net proceeds to the Trust


(9,383
)

(3,585
)

(12,968
)Revisions of previous estimates


3,810


(21
)

3,789Accretion of discount


3,378


2,948


6,326Net change in price and production costs


(682
)

(287
)

(969
)Other


2,825


(3,749
)

(924
)Standardized measure, December 31, 2007

$
33,727

$
24,787

$
58,514


F-13

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The following is a summary of royalty income and distributable income per unit by quarter in 2007, 2006 and 2005 (all amounts in thousands except Distributable
income per unit):

|2007                          |  | Mar 31 |        | June 30 |   | Sept 30 |  | Dec 31 |        | Total
|----------------------------- |  | ------ | ------ | ------- | - | ------- |  | ------ | ------ | -----
|Royalty Income                |  | $      | 3,565  |         | $ | 3,855   |  | $      | 3,694  |      
|Distributable Income          |  | $      | 2,832  |         | $ | 3,144   |  | $      | 3,084  |      
|Distributable Income Per Unit |  | $      | 0.4800 |         | $ | 0.5328  |  | $      | 0.5228 |      

|
|

|2006                          |  | Mar 31 |        | June 30 |   | Sept 30 |  | Dec 31 |        | Total
|----------------------------- |  | ------ | ------ | ------- | - | ------- |  | ------ | ------ | -----
|Royalty Income                |  | $      | 5,363  |         | $ | 4,595   |  | $      | 4,300  |      
|Distributable Income          |  | $      | 4,385  |         | $ | 3,780   |  | $      | 3,313  |      
|Distributable Income Per Unit |  | $      | 0.7432 |         | $ | 0.6407  |  | $      | 0.5616 |      

|
|

|2005                          |  | Mar 31 |        | June 30 |   | Sept 30 |  | Dec 31 |        | Total
|----------------------------- |  | ------ | ------ | ------- | - | ------- |  | ------ | ------ | -----
|Royalty Income                |  | $      | 3,648  |         | $ | 3,914   |  | $      | 4,659  |      
|Distributable Income          |  | $      | 2,958  |         | $ | 3,206   |  | $      | 3,800  |      
|Distributable Income Per Unit |  | $      | 0.5014 |         | $ | 0.5434  |  | $      | 0.6440 |      

F-14

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