Use these links to rapidly review the documentTABLE OF CONTENTS Item 8. Financial Statements and Supplementary Data.

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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 1934FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934FOR THE TRANSITION PERIOD
FROM                                  TOCommission file number: 1-11748


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

Delaware

36-7034603(State or other Jurisdiction of
Incorporation or Organization)

(I.R.S. Employer Identification No.)The Bank of New York Mellon Trust Company, N.A., 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and
post such files). Yes o    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 March 1, 2010, 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, as of March 1, 2010, 288,100 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, 2009 of $24.00 was approximately $135 million.

Documents
Incorporated By Reference:None



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TABLE OF CONTENTS



PART IItem 1.

Business

3Description of the Trust

3The Net Profits Interests

5The Underlying Properties

9Competition and Markets

13Regulation of Natural Gas

13Health, Safety and Environmental Regulation

13Description of Trust Units and Depositary Units

15Federal Income Tax Matters

17State Tax Considerations

17Available Information

18Item 1A.

Risk Factors

18Item 1B.

Unresolved Staff Comments

21Item 2.

Properties

21Item 3.

Legal Proceedings

21Item 4.

[Reserved]

21PART II

22Item 5.

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

22Item 6.

Selected Financial Data

22Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operation

22Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

26Item 8.

Financial Statements and Supplementary Data

27Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure

27Item 9A.

Controls and Procedures

27Item 9B.

Other Information

28PART III

29Item 10.

Directors, Executive Officers, and Corporate Goverance

29Item 11.

Executive Compensation

29Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters

29Item 13.

Certain Relationships and Related Transactions, and Director
Independence

30Item 14.

Principal Accounting Fees and Services

30PART IV

31Item 15.

Exhibits, Financial Statement Schedules

31SIGNATURES

32


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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 (meaning all 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 those contemplated by any forward-looking statements. The Trustee disclaims any obligation 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 and elsewhere in this Report,
including, without limitation, those contained below under the heading "Risk Factors".

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 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 Energy Corporation of America ("ECA").

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
Energy Corporation, as grantor, Bank of Montreal Trust Company, as trustee, and Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee"). Until January 1, 2010, Eastern American
Energy Corporation was a wholly-owned subsidiary of Energy Corporation of America. Effective January 1, 2010, Eastern American Energy Corporation was merged into Energy Corporation
of America, with Energy Corporation of America being the surviving corporation. Except as otherwise required by the context, references herein to "ECA" mean Eastern American Energy Corporation at all
times prior to January 1, 2010, and mean Energy Corporation of America at all times on and after January 1, 2010. The merger of Eastern American Energy Corporation into its parent Energy
Corporation of America is not expected to have any significant effect on the Trust.

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

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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 Company, N.A. (now known as The Bank of New York Mellon Trust 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 Mellon 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 ECA 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. ECA was obligated to drill and complete, at its expense,
65 development wells (the "Development Wells") on the development well locations conveyed to the Trust. ECA 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 ECA 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 2009 were $108,000. The total of all Trustee fees and Trust administrative expenses for 2009 was $615,789. Such costs could
fluctuate in the future depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and

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engineering
services. In addition to such expenses, in 2009, the Trust paid ECA an overhead reimbursement of $364,136. 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 Conveyance", and
together with the Royalty NPI Conveyance, the "Conveyances"). Forms of the Conveyances have been filed as exhibits to this Form 10-K.

The
Underlying Properties are subject to and burdened by the Net Profits Interests. The interests of ECA 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
ECA, 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 has been produced which is attributable to ECA's net revenue interests in the properties burdened by the Term
NPI. As of December 31, 2009, 25,697 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".

ECA
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, ECA 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. Prior to January 1, 2010, the limitations on ECA's right to transfer a portion of the Underlying Properties included limitations on the aggregate sales proceeds
for any such sales. As of January 1, 2010, the limitations on the aggregate sales proceeds no longer apply. 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.

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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.

"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 2009 was $647,917, for 2008 was $617,564 and for 2007 was $588,160.
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 5.0%. 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, ECA 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. ECA, 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 ECA'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 ECA's or the Trust's interests in the Underlying Properties, or production therefrom.

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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 ECA may recover the amount of such overpayments from future distributions in accordance with the Conveyances.

The
Conveyances require ECA to maintain books, records, and accounts sufficient to calculate the volumes of gas and the share of Net Proceeds payable to the Trust. ECA 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.

Gas Purchase Contract

Gas production attributable to the Net Profits Interests is purchased from the Trust by Eastern Marketing, a wholly owned subsidiary of
ECA, 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

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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 ECA 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 is purchased by Eastern Marketing pursuant to the Gas Purchase Contract, which
expires upon the Liquidation Date of the Trust. ECA 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.

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 per unit for each of the quarters in
2009 were $0.3312, $0.2515, $0.2648 and $0.2587, 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

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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

ECA 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 ECA and the Trust
in determining whether a well is capable of producing in paying quantities, ECA 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 ECA or any of its affiliates that may result from the performance by Eastern Marketing of its obligations under the Gas Purchase Contract.

ECA
has the right, pursuant to the Conveyances, to sell all or any portion of the Underlying Properties without restrictions and without the consent of the Trust or the Unitholders;
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 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, ECA 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 ECA's working interests in certain properties located in the Appalachian Basin states of
West Virginia and Pennsylvania. As of December 31, 2009, such properties consisted of 668 producing gas wells. The working interests of ECA 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. ECA'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, 2009, proved

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developed
reserves attributable to the Net Profits Interests (reflecting quantities of gas free of future costs and expenses based on estimated prices) were approximately 10,700 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.

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

ECA
acquired its interests in the Underlying Properties under or through (i) oil and gas leases granted by the mineral owner directly to ECA, (ii) assignments of oil and
gas leases by the lessee who originally obtained the leases from the mineral owner, (iii) farmout agreements that grant ECA 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 ECA.

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, 2009,
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, 2009 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

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Report.
The Term NPI excludes production beyond the earlier of May 15, 2013 or such time as 41,683 MMcf has been produced which is attributable to ECA'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 Annex A hereto.

Proved Gas ReservesDiscounted
Estimated
Future Net
Revenues(2)Developed

(MMcf)
Undeveloped

Total

Estimated
Future Net
Revenues(2)(Dollars in thousands)Underlying Properties(1)


29,233


0


29,233

$
123,221

$
50,487Net Profits Interests:Royalty NPI


8,383


0


8,383

$
46,418

$
19,490Term NPI


2,317


0


2,317


12,830


10,968Total


10,700


0


10,700

$
59,248

$
30,458


---

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.

Preparation of reserve report.

As described in this Report, the interests held by the Trust consist of a net profits interest derived from working and royalty
interests. The net profits interest does not entitle
the Trust to a specific quantity of oil or gas but to 90 percent of the net proceeds of the relevant production.

The
Trust retained Ryder Scott Company L.P. ("Ryder Scott"), which is an independent petroleum engineering consulting firm that has been providing petroleum consulting services
throughout the world for over seventy years, to prepare a third party report of the reserves attributable to the net profits interest. A signed copy of the report, dated February 5, 2010 (the
"Reserve Report"), is attached as Annex A to this Report on Form 10-K and filed as exhibit 99.1. As stated in the Reserve Report, the estimates contained therein are
based on accounts, records, geological and engineering data and reports and other data provided to Ryder Scott by ECA and are based on data available through August, 2009. The Trust has no access to,
and its internal controls do not cover, the geological, engineering or other data and information provided by ECA to Ryder Scott in connection with the preparation of the

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Reserve
Report. The qualifications of Mr. Larry Thomas Nelms, the technical person primarily responsible for overseeing the preparation of the Reserve Report are as follows. Mr. Nelms,
an employee of Ryder Scott since 1983, is a Managing Senior Vice President and also serves as a member of the Board of Directors, responsible for coordinating and supervising staff and consulting
engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Nelms served in a number of engineering positions with various oil and gas companies.
Mr. Nelms earned a Bachelor of Science degree in Mechanical Engineering from Mississippi State University in 1963 and a Master of Science from the University of New Mexico in 1965, and he is a
registered Professional Engineer in the State of Colorado. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, where he serves as chairman of
the Denver Section and also served for three years on the board of directors. As part of his 2009 continuing education hours, Mr. Nelms attended an internally presented 16 hours of
formalized training as well as the day long 2009 RSC Reserves Conference forum, and a presentation at the Denver Section of SPEE relating to the definitions and disclosure guidelines contained
in the SEC's Modernization of Oil and Gas Reporting rules. Mr. Nelms has served as the instructor of the PetroSkills course entitled "Oil & Gas Reserve Evaluation" for a period of four
years. Based on his education, background, professional training and more than 25 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Nelms has
attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information" promulgated by the Society of Petroleum Engineers as of February 18, 2007.

The
Reserve Report was prepared for the Trust primarily to comply with the requirements of the Amended and Restated Trust Agreement pursuant to which the Trust was originally created. It
was completed on February 5, 2010 and has an effective date of December 31, 2009. The report covers all of the registrant's interest in the net profits interest. The properties to which
the net profits interest relate are located in the United States, specifically in West Virginia and Pennsylvania. The estimated reserves and future net income amounts presented in the Reserve Report,
as of December 31, 2009 are related to hydrocarbon prices, computed in accordance with the gas contract described below and applicable SEC rules. The hydrocarbon prices used in the preparation
of the Reserve Report are based on the average prices during the 12-month period prior to the ending date of the period covered in the Reserve Report, determined as unweighted arithmetic
averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements
as required by the SEC regulations. For purposes of the Reserve Report, the proved reserves attributable to the net profits interest have been proportionately reduced to reflect the future estimated
costs and expenses deducted in the calculation of Net Proceeds. Accordingly, the reserves presented reflect quantities of gas that are free of future costs or expenses based on the price and cost
assumptions utilized in the Reserve Report. The Reserve Report utilized the terms of the gas contract between Eastern Marketing Corporation (a wholly owned subsidiary of ECA) and the Trust. Under the
gas contract, The Trust receives the Henry Hub Average Spot Price (defined as described below) 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
theWall 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 Trust believes

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that
the assumptions, data, methods and procedures utilized by Ryder Scott are appropriate for the purpose served by the Reserve Report, and believes that Ryder Scott has used all methods and
procedures Ryder Scott considered necessary under the circumstances to prepare the Reserve Report.

A
brief summary of Ryder Scott's conclusions with respect to the matters covered by the Reserve Report is set forth above under "Proved Reserves of Underlying
Properties and Net Profits Interests." Other matters, including a discussion of the inherent uncertainties of reserves estimates, are also contained elsewhere in this Report on
Form 10-K and in the Reserve Report.

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 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 ECA
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 ECA 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 ECA for certain Capital Costs associated with

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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 ECA has
held an interest for a relatively short period of time prior to the effective date of the Conveyances. ECA 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 or that hydrocarbons or other solid or hazardous wastes 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, ECA 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 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". ECA 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.

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DESCRIPTION OF TRUST UNITS AND DEPOSITARY UNITS

The following information is subject to the detailed provisions of the Deposit Agreement originally entered into by ECA, 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 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

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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 TaxMatters".

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.

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.

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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, ECA 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

The Trust is a grantor trust and therefore is not subject to federal income taxes. Accordingly, no recognition has been given to
federal income taxes in the Trust's financial statements. The Trust Unitholders are treated as the owners of Trust income and assets, and the entire federal taxable income of the Trust will be
reported by the Trust Unitholders on their respective tax returns.

The
Trustee assumes that the Depository Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint
owners, and brokers holding an interest for a custodian in street name, referred to herein collectively as "middlemen"). Therefore, the Trustee considers the Trust to be a widely held fixed investment
trust ("WHFIT") for federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., Trustee, Global Corporate Trust, 919 Congress Avenue, Suite 500 Austin, Texas 78701, is the
representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT.

Notwithstanding
the foregoing, the middlemen holding the Depository Units on behalf of Unitholders, and not the Trustee of the Trust, are solely responsible for complying with the
information reporting requirements under the Treasury Regulations with respect to such Depositary Units, including the issuance of IRS Forms 1099 and certain written tax information statements
to the investor.

Each
Unitholder should consult his or her tax advisor regarding Trust tax compliance matters.

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 6.5% 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

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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.

Available Information

The Trust makes copies of its reports under the Exchange Act available at www.businesswire.com/cnn/ngt.htm. The Trust's filings under the
Exchange Act are also available electronically from the website maintained by the
Securities and Exchange Commission at http://www.sec.gov. The Trust will also provide electronic and paper copies of its recent filings free of charge 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 ECA and the Trust. These factors include:



Low gas prices may reduce production.

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.

Estimated reserves and future production levels are uncertain.

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

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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.

There are risks inherent in the development and production of natural gas.

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.

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 ECA. As operator, ECA 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.

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.

Compliance with governmental regulations may be expensive.

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.

Operating costs, capital expenditures and taxes reduce payments to the Trust.

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 reduce distributions to Unitholders.

Administrative costs, including the Trustee's fee and other 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, ECA 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, ECA recorded the Conveyances in the real property records of West Virginia and Pennsylvania in accordance with local
recording acts. ECA believes that, if, during the term of the Trust, ECA 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

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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 ECA. 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, ECA 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.

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

The Net Profits Interests are subject to any defects in ECA's rights with respect to the Underlying Properties. ECA 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, ECA 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.

Taxable income could exceed cash distributions.

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.

ECA and the Trust may have conflicts of interest.

The interests of ECA and the interests of the Trust and the Unitholders may at times be different. For example, ECA'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, ECA 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 ECA under the
Gas Purchase Contract. In addition, ECA 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 ECA from drilling additional wells on the same property as the wells subject to the Net Profits Interests provided that ECA
complies with both of these covenants. In addition, these covenants would not prohibit ECA from drilling development wells on adjacent properties provided that ECA complies with the 1,000 foot
limitation. If ECA is permitted under these covenants to drill additional development wells near the wells subject to the Net Profits Interests, the additional wells could cause

20

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drainage
of the reserves attributable to the Net Profits Interests. These covenants apply only to ECA, and do not apply to third parties.

In
addition, ECA's interests may conflict with those of the Trust and the Unitholders in situations involving the sale of Underlying Properties. ECA has the right to sell all or any
portion of the Underlying Properties without restrictions; however, except in limited circumstances where ECA 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 ECA. ECA 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.

Unitholders have only limited voting rights.

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.

Unitholders could be subject to unlimited liability.

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 would give effect to such
limitation.

There are risks associated with the financial position of ECA.

ECA 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 ECA 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 ECA.

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.    [Reserved].

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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 closing prices and
distributions paid during the quarters in the two-year period ended December 31, 2009 were as follows:

Quarter

High

Low

Distributions
Paid2008:First (to March 31, 2008)

$
28.60

$
26.36

$
0.4700Second (to June 30, 2008)

$
30.84

$
27.65

$
0.6706Third (to September 30, 2008)

$
30.61

$
24.50

$
0.7291Fourth (to December 31, 2008)

$
26.76

$
22.74

$
0.51162009:First (to March 31, 2009)

$
26.92

$
22.61

$
0.3312Second (to June 30, 2009)

$
26.01

$
23.86

$
0.2515Third (to September 30, 2009)

$
24.25

$
23.00

$
0.2648Fourth (to December 31, 2009)

$
24.29

$
23.23

$
0.2587


At
March 1, 2010, the 5,900,000 Depositary Units outstanding were held by approximately 200 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, 2009 to December 31, 2009 were $950.80 and
$899.50, respectively. The closing price on December 31, 2009 was $935.90 per $1,000 face amount.

During
the fourth quarter of 2009, 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 EndedDecember 31,
2009

December 31,
2008

December 31,
2007

December 31,
2006

December 31,
2005Royalty Income

$
8,868,114

$
17,028,373

$
14,660,909

$
17,663,792

$
18,179,459Distributable Income

$
6,526,597

$
14,049,648

$
12,006,605

$
14,158,872

$
14,597,387Distribution Amount

$
6,526,597

$
14,049,648

$
12,506,605

$
14,658,872

$
13,712,387Distributable Income per unit

$
1.1062

$
2.3813

$
2.0350

$
2.3998

$
2.4741Distribution Amount per unit

$
1.1062

$
2.3813

$
2.1198

$
2.4846

$
2.3241Total assets at year end

$
18,635,014

$
22,570,038

$
24,953,135

$
28,165,747

$
32,954,834




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.

During
the fourth quarter of 2009 an oil and gas company contacted ECA to inquire as to whether it would assign the Bond J-748 gas well ("Well") which is a well in which the
Trust owns a Net Profits Interest. ECA reviewed the Trust Agreement and certified to the Trustee that the Well could be sold free from the Net Profits Interest and that assignment of the Well did not
conflict with the provisions of section 3.02 of the Second Amended and Restated Trust Agreement. The Well had not produced since 2006 due to mechanical problems and had become uneconomic to
produce. The Well was assigned to avoid potential plugging and abandonment costs and liabilities. The Trust received no cash distribution for the assignment of the Well due to the fact that the Well
was transferred for no cash consideration.

Also,
during the fourth quarter of 2009 the Sheilds #1 gas well ("Well"), a Well in which the Trust owns a Net Profits Interest, was plugged and abandoned. The Well had not been
producing due to down-hole mechanical problems and was no longer capable of commercial production. Therefore, the Well was plugged and abandoned in accordance with the regulations of the
Pennsylvania Department of Environmental Protection.

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 2009 was $615,789, including the Trustee's fee of $108,000. In addition to such expenses, in 2009, the
Trust paid ECA an overhead reimbursement of $364,136. The overhead reimbursement increases by 3.5% per year and is payable
quarterly. 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.

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

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$108,000
plus fees and expenses. Effective October 2, 2006, The Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.) acquired the corporate trust
business of JPMorgan Chase Bank, N.A. Consequently, The Bank of New York Mellon 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.

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 assessed to determine whether their net capitalized cost is impaired, whenever events
or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to The Financial Accounting Standards Board ("FASB") Accounting Standards Codification 360, Property,
Plant and Equipment ("ASC 360"). 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 fair value of the investment in net profits interests 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
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.

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. The estimates include an estimate of the revenues attributable to the Trust from natural gas production
for the last several months of the year, as the revenues from natural gas

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Table of Contents

sales
are typically received several months after delivery. Actual results could differ from those estimates.

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, 2009. At December 31, 2009, the Trust had General and Administrative Expenses Payable of $213,744 and
Distributions Payable of $1,526,481.

Results of Operations

2009 Compared with 2008

The Trust's Distributable Income was $6,526,597 for the year ended December 31, 2009 as compared to $14,049,648 for the year
ended December 31, 2008. This decrease was due to a decrease in Royalty Income for the year ended December 31, 2009 ($8,868,114) as compared to the year ended December 31, 2008
($17,028,373). The decrease in Royalty Income was due to a decrease in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($5.534 per Mcf for the year ended
December 31, 2009 as compared to $10.406 per Mcf for the year ended December 31, 2008). The decrease was also partially due to a decrease in production of gas attributable to the Net
Profits Interests for the year ended December 31, 2009 (1,604 Mmcf) as compared to the year ended December 31, 2008 (1,637 Mmcf). The decline in production is primarily attributable to
natural production declines. Taxes on Production and Property were $676,110 for the year ended December 31, 2009 as compared to $1,254,139 for the year ended December 31, 2008. The
decrease in taxes is due directly to the decrease in Royalty Income as discussed above. Trust General and Administrative Expenses were $979,925 for the year ended December 31, 2009 as compared
to $1,107,022 for the year ended December 31, 2008. The decrease in General and Administrative Expenses was due primarily to a decrease in professional fees incurred.

Amortization
of Net Profits Interests in Gas Properties was $2,370,117 for the year ended December 31, 2009 as compared to $2,558,284 for the year ended December 31, 2008.
This decrease was due to the decrease in production volumes and a decrease in the depletion rate to $1.4769 for the year ended December 31, 2009 from $1.5627 for the year ended
December 31, 2008.

The
average price payable to the Trust for gas production attributable to the Net Profits Interests was $5.534 per Mcf for the year ended December 31, 2009 and $10.406 per Mcf for
the year ended December 31, 2008. The price per Mcf was lower for the year ended December 31, 2009 than for the year ended December 31, 2008 due to a decrease in the average spot
market price for gas delivered at the Henry Hub near Henry, Louisiana ($4.731 per Dth for the year ended December 31, 2009 as compared to $9.160 per Dth for the year ended December 31,
2008).

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Table of Contents

2008 Compared with 2007

The Trust's Distributable Income was $14,049,648 for the year ended December 31, 2008 as compared to $12,006,605 for the year
ended December 31, 2007. This increase was due to an increase in Royalty Income for the year ended December 31, 2008 ($17,028,373) as compared to the year ended December 31, 2007
($14,660,909). The increase in Royalty Income was due to an increase in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($10.406 per Mcf for the year ended
December 31, 2008 as compared to $8.339 per Mcf for the year ended December 31, 2007). The increase was partially offset due to a decrease in production of gas attributable to the Net
Profits Interests for the year ended December 31, 2008 (1,637 Mmcf) as compared to the year ended December 31, 2007 (1,758 Mmcf). The decline in production is primarily attributable to
natural production declines. Taxes on Production and Property were $1,254,139 for the year ended December 31, 2008 as compared to $1,104,557 for the year ended December 31, 2007. The
increase in taxes is due directly to the increase in Royalty Income as discussed above. Trust General and Administrative Expenses were $1,107,022 for the year ended December 31, 2008 as
compared to $961,587 for the year ended December 31, 2007. The increase in General and Administrative Expenses was due primarily to an increase in professional fees incurred.

During
the year ended December 31, 2008, the Trustee did not refund any amount from the Cash Reserve balance compared to the refunding of $500,000 from the cash reserve for the
year ended December 31, 2007. This Reserve was established to facilitate the payment of vendor invoices on a timely basis. Amortization of Net Profits Interests in Gas Properties was $2,558,284
for the year ended December 31, 2008 as compared to $2,938,058 for the year ended December 31, 2007. This decrease was due to the decrease in production volumes and a decrease in the
depletion rate to $1.5627 for the year ended December 31, 2008 from $1.6709 for the year ended December 31, 2007.

The
average price payable to the Trust for gas production attributable to the Net Profits Interests was $10.406 per Mcf for the year ended December 31, 2008 and $8.339 per Mcf for
the year ended December 31, 2007. The price per Mcf was higher for the year ended December 31, 2008 than for the year ended December 31, 2007 due to an increase in the average
spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($9.160 per Dth for the year ended December 31, 2008 as compared to $7.281 per Dth for the year ended
December 31, 2007).

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 Eastern Marketing, a wholly owned subsidiary of ECA pursuant to the Gas
Purchase Contract described herein.

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Table of Contents

Item 8.Financial Statements and Supplementary Data.



Financial StatementsReport of Independent Registered Public Accounting Firm

F-2Statements of Assets, Liabilities and Trust Corpus as of December 31, 2009
and 2008

F-4Statements of Distributable Income for the years ended December 31, 2009,
2008 and 2007

F-5Statements of Changes in Trust Corpus for the years ended December 31, 2009,
 2008 and 2007

F-6Notes to Financial Statements

F-7Supplemental Reserve Information (Unaudited)

F-13


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, Energy Corporation of America ("ECA"), and the independent reserve engineer to The Bank of New York Mellon 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 ECA.

As
of December 31, 2009, 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 at a reasonable assurance level.

Due
to the contractual arrangements of (i) the Trust Agreement and (ii) the rights of the Trustee under the Conveyances regarding information furnished by ECA, 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:



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Other
than reviewing the financial and other information provided to the Trust by ECA 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.

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, 2009. The effectiveness of the Trust's internal control over financial reporting as of December 31, 2009 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.

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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 New York Mellon 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, 2009,
December 31, 2008 and December 31, 2007, The Bank of New York Mellon Trust Company, N.A., as Trustee, received $108,000 annually, as Trustee fees and $507,789, $647,198 and $513,663,
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.

(a)   Security
Ownership of Certain Beneficial Owners.

Based
on filings with the Securities and Exchange Commission, the Trust is not aware of any person owning beneficially more than 5% of the Units as of March 1, 2010, except as
follows:

Name

Number of Shares

Percent of ClassLucas Capital Management LLC(1)


325,425


5.5
%2 Bridge Ave.
Red Bank NJ 07701Branzan Investment Advisors, Inc.(2)


336,950


5.7
%


(1)Reference
is hereby made to the Schedule 13G filed by Lucas Capital Management LLC on January 14, 2010 for information regarding the
ownership of the reporting person.(2)Reference
is hereby made to the Schedule 13G filed by Branzan Investment Advisors, Inc. on August 19, 2009 for information regarding
the ownership of the reporting person.


(b)   Security
Ownership of Management.

Not
applicable.

(c)   Changes
in Control.

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.

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(d)   Securities
authorized for issuance under equity compensation plans.

The
Trust has no equity compensation plans.

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

The Trust has no directors. Since January 1, 2009, there has not been, and there is not currently proposed, any transaction or
series of similar transactions requiring disclosure under Item 404 of Regulation S-K.

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 $205,000 in 2009 and $210,078 in 2008.

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 $107,250 in 2009 and $103,000 in 2008.

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.

30

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PART IV

Item 15.Exhibits, Financial Statement Schedules.



ReportsReserve Report of Ryder Scott Company, Independent Petroleum Engineers

A-1Financial StatementsThe 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-2Statements of Assets, Liabilities and Trust Corpus as of December 31, 2009
and 2008

F-4Statements of Distributable Income for the years ended December 31, 2009,
2008 and 2007

F-5Statements of Changes in Trust Corpus for the years ended December 31, 2009,
 2008 and 2007

F-6Notes to Financial Statements

F-7Supplemental Reserve Information (Unaudited)

F-13


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 Exhibits 31, 32 and 99.1, 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 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
Number3.1

Second Amended and Restated Trust Agreement of Eastern American Natural Gas Trust4.1

Specimen Depositary Receipt4.2

Form of NPI Royalty Deposit Agreement10.1

Form of Conveyance10.2

Form of Term NPI Conveyance10.3

Form of Gas Purchase Contract between Eastern American Energy Corporation, Eastern American Marketing Corporation and Eastern American Natural Gas Trust10.4

Form of Conveyance of Production Payment/Assignment of Production from Eastern American Natural Gas Trust to Eastern American Marketing Corporation10.5

Form of Assignment and Standby Performance Agreement31

Rule 13a-14(a)/15d-14(a) Certification32

Section 1350 Certification99.1

Report of Ryder Scott Company L.P. dated February 5, 2010


31

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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 15th day of March, 2010.

EASTERN AMERICAN NATURAL GAS TRUSTBy:

The Bank of New York Mellon Trust Company, N.A., TrusteeBy:

/s/ MIKE ULRICHName:

Mike UlrichTitle:

Vice President


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.

32

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GRAPHIC

February 5,
2010

Eastern
American Natural Gas Trust
The Bank of New York Mellon 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,
2009. 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). As of January 1, 2010 EAEC merged with and into ECA with ECA being the surviving entity and now ECA, by operation of law, is the owner of the underlying properties
burdened by the Net Profits Interest owned by the Trust. 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 reserves and future net income amounts presented in this report, as of December 31, 2009 are related to hydrocarbon prices. The hydrocarbon prices used in the
preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic
averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements
as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income
actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below

As of December 31, 2009Proved Net Developed

Gas

Estimated
Future Net
Cash Inflows

Present
Value
At 10%(MMCF)

(M$)

(M$)Royalty NPI


8,383


46,418


19,490Term NPI


2,317


12,830


10,968Total


10,700


59,248


30,458


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, 2010 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 ECA. 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

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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 ECA will vary in the future as relative estimates of future gross revenues and
future net incomes vary. Furthermore, ECA 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 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 and income data were estimated based on the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17,
Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

Securities
and Exchange Commission Regulation S-X §229.4-10(a) (22) defines proved oil and gas reserves as follows:

Proved
oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically
produciblefrom a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulationsprior to the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.



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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, 2009 from this report are presented in the following table:

As of December 31, 2009Total Proved

Royalty
NPI

Term
NPI

TotalsFuture Cash Inflows (M$)


46,418


12,830


59,248Future CostsProduction (M$)


0


0


0Development (M$)


0


0


0Total Costs (M$)

$
0


0


0Future Net Cash InflowsBefore Income Tax (M$)


46,418


12,830


59,248Present Value at 10%Before Income Tax (M$)


18,308


10,333


28,641




As of December 31, 2009Proved Net Developed Reserves

Royalty
NPI

Term
NPI

TotalsGas (MMCF)


8,383


2,317


10,700Proved Net Undeveloped ReservesGas (MMCF)


0


0


0Total Proved Net ReservesGas (MMCF)


8,383


2,317


10,700


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.

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This
report utilized the terms of the gas contract between Eastern Marketing Corporation (a wholly owned subsidiary of ECA) 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. ECA computed the "Variable" price under the gas contract as of
December 31, 2009 as $5.537 per Mcf, utilizing $4.731 as the Henry Hub Average Spot Price computed in accordance with the gas contract but utilizing the SEC guidelines that require the price to
be based on the 12-month period prior to the ending date of the period covered in this report .

Operating
costs for the leases and wells in this report were supplied by ECA 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. ECA 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 August, 2009.

At
the time of formation of the Trust, ECA assigned The Trust an interest in 65 undeveloped locations. During the period 1993 through 1998, ECA 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.

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 ECA. Moreover, due to the nature of the Net

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Table of Contents

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

Estimated
Net Reserve Data
Certain Combined Leasehold Interests of
Energy Corporation of America
And The Trust
As of December 31, 2009
SEC Parameters

ProvedTotal
ProvedNet Remaining Reserves

Developed

UndevelopedGas-MMCF


29,233


0


29,233


The
estimated future net income associated with the foregoing volumes and the 10 percent discounted estimated future net income was $123,220,946 and $50,486,568, 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.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout
the world for over seventy years. Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists
on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We
do not serve as officers or directors of any publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows
us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder
Scott actively participates in industry related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many
of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively
participating in ongoing continuing education.

Ryder
Scott requires that staff engineers and geoscientists have received professional accreditation, and are maintaining in good standing, a registered or certified professional
engineer's license or a

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registered
or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization
prior to becoming an officer of the Company.

We
are independent petroleum engineers with respect to Energy Corporation of America. Neither we nor any of any of our employees have any interest in the subject properties and neither
the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The
professional qualifications of the undersigned, the technical person primarily responsible for preparing the reserves information discussed in this report, are included as an
attachment to this letter.

Terms of Usage

This report was prepared for the exclusive use and sole benefit of Eastern American Natural Gas Trust and Energy Corporation of America
and may not be put to other use without our prior written consent for such use. The data and work papers used in the preparation of this report are available for examination by authorized parties in
our offices. Please contact us if we can be of further service.

Very truly yours,RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580GRAPHIC

GRAPHICLarry T. Nelms P. E. Managing Senior Vice President


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EASTERN AMERICAN NATURAL GAS TRUST



FINANCIAL
STATEMENTS

as
of December 31, 2009 and 2008
and for the years ended
December 31, 2009, 2008 and 2007

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Table of Contents

Report of Independent Registered Public Accounting Firm

To
the Unit Holders of Eastern American Natural Gas Trust and
The Bank of New York Mellon 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, 2009 and 2008, 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, 2009. We also have audited the Trust's
internal control over financial reporting as of December 31, 2009, based on criteria established inInternal ControlIntegrated
Frameworkissued 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, 2009 and 2008, and the
distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2009, on the

F-2

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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, 2009,
based on criteria established inInternal ControlIntegrated Frameworkissued by COSO.

/s/
PricewaterhouseCoopers LLP

Pittsburgh,
Pennsylvania
March 12, 2010

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Table of Contents

EASTERN AMERICAN NATURAL GAS TRUST        STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS        as of December 31, 2009 and 2008

2009

2008Assets:Cash

$
140,972

$
121,173Prepaid Expenses


25,000


Net Proceeds Receivable


1,774,283


3,383,989Net Profits Interests in Gas Properties


93,162,180


93,162,180Accumulated Amortization


(76,467,421
)

(74,097,304
)16,694,759


19,064,876Total Assets

$
18,635,014

$
22,570,038Liabilities and Trust Corpus:Trust General and AdministrativeExpenses Payable

$
213,774

$
286,764Distributions Payable


1,526,481


3,018,398Trust Corpus (5,900,000 units authorized and outstanding)


16,894,759


19,264,876Total Liabilities and Trust Corpus

$
18,635,014

$
22,570,038


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

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Table of Contents

EASTERN AMERICAN NATURAL GAS TRUST        STATEMENTS OF DISTRIBUTABLE INCOME        for the years ended        December 31, 2009, 2008 and 2007

2009

2008

2007Royalty Income

$
8,868,114

$
17,028,373

$
14,660,909Operating Expenses:Taxes on Production and Property


676,110


1,254,139


1,104,557Operating Cost Charges


685,529


617,564


588,160Total Operating Expenses


1,361,639


1,871,703


1,692,717Net Proceeds to the Trust


7,506,475


15,156,670


12,968,192General and Administrative Expenses


979,925


1,107,022


961,587Interest Income


47





Distributable Income


6,526,597


14,049,648


12,006,605Cash Reserve Refunded (Withheld)








500,000Distribution Amount

$
6,526,597

$
14,049,648

$
12,506,605Distributable Income Per Unit (5,900,000 units authorized and outstanding)

$
1.1062

$
2.3813

$
2.0350Distribution Amount Per Unit (5,900,000 units authorized and outstanding)

$
1.1062

$
2.3813

$
2.1198


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

F-5

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Table of Contents

EASTERN AMERICAN NATURAL GAS TRUST        STATEMENTS OF CHANGES IN TRUST CORPUS        for the years ended        December 31, 2009, 2008 and 2007

2009

2008

2007Trust Corpus, Beginning of Period

$
19,264,876

$
21,823,160

$
25,261,218Distributable Income


6,526,597


14,049,648


12,006,605Distributions Paid or Payable to Unitholders


(6,526,597
)

(14,049,648
)

(12,506,605
)Amortization of Net Profits Interests in Gas Properties


(2,370,117
)

(2,558,284
)

(2,938,058
)Trust Corpus, End of Period

$
16,894,759

$
19,264,876

$
21,823,160


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

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Table of Contents

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 Energy Corporation of
America ("ECA"), 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 (now known as The Bank of New York Mellon Trust Company, N.A.), effective as of
October 2, 2006. The transfer agent for the Trust is Bondholder Communications, an affiliate of The Bank of New York Mellon Trust Company, N.A.

The
purpose of the Trust is to acquire and hold net profits interests owned by ECA 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 ECA. 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. ECA 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 ECA's net revenue interests in the properties burdened by the Term
NPI. As of December 31, 2009, 25,697 MMcf of such gas had been produced.

ECA
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, ECA 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, ECA had a disagreement with the Trust over ECA's obligation to drill these closely offset development wells. The Trust agreed that, in lieu of drilling these closely offset
development wells ECA 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.

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Table of Contents

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 ECA was unable to cure various title defects associated with these wells. ECA 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 ECA under the Reasonably Prudent Operator Standard then such drill site(s) shall
be construed as a development well(s). Consequently, ECA 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 ECA 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-8

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Table of Contents

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 assessed to determine whether their net capitalized cost is impaired, whenever events
or changes in circumstances indicate that its carrying amount may not be recoverable, pursuant to ASC 360. 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 fair value of the investment in net profits interests attributable to proved gas reserves of
the Underlying Properties. Any such writedown would not reduce Distributable Income, although it would reduce Trust Corpus. No impairment in the Underlying Properties was recognized during the three
and twelve month periods ended December 31, 2009.

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 ECA, require payment with respect to gas

F-9

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Table of Contents

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

2.Significant Accounting Policies: (Continued)

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. The estimates include an estimate of
the revenues attributable to the Trust from natural gas production for the last several months of the year, as the revenues from natural gas sales are typically received several months after delivery.
Actual results could differ from those estimates.

Segment 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.Effects of New Pronouncements:

In January 2009, the SEC published its final rule regarding the modernization of oil and gas reporting, which modifies the SEC's reporting and disclosure rules for oil and gas reserves.
The most notable changes of the final rule include the replacement of the single day period-end pricing to value natural gas and oil reserves to a 12-month average of the first
day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, disclosure previously prohibited by SEC rules.
The revised reporting and disclosure requirements were effective for us as of December 31, 2009. Early adoption was not permitted.

In
January 2010, the FASB issued changes in its oil and gas reserve estimation and disclosure requirements to align them with the SEC's final rule discussed above. These changes were
also effective for us as of December 31, 2009.

We
applied the above changes to our financial statements as of and for the year ended December 31, 2009. The impact of the adoption of the SEC final rule on our financial
statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old
and new rules.

In
May 2009, the Financial Accounting Standards Board (FASB) issued FASB ASC 855,Subsequent Events("ASC 855"). ASC 855 establishes
principles and standards related to the accounting for and disclosure of events that occur after the date of the balance sheet included in financial statements being presented, but before such
financial statements are issued. ASC 855 requires an entity to recognize, in the financial statements, subsequent events that provide additional information regarding conditions that existed at the
balance sheet date. Subsequent events that provide information about conditions that did not exist at the balance sheet date are not to be recognized in the financial statements under ASC 855. ASC 855
is effective for interim and annual reporting periods ending after June 15, 2009. The Trust adopted this standard effective as of June 30, 2009. The adoption of ASC 855 did not have a
material effect on the Trust's financial statements.

In
June 2009, the FASB issued a statement that establishes the FASB Accounting Standards Codification as the source of authoritative U.S. generally accepted accounting principles
(U.S. GAAP).

F-10

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Table of Contents

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

3.Effects of New Pronouncements: (Continued)

The
Codification, which changes the referencing of financial standards, became effective for our third quarter 2009 financial statements and did not have an impact on the Trust's financial statements.
The Codification did not change or alter existing U.S. GAAP.

4.Income Taxes:

Tax counsel to ECA advised ECA 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.

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.

5.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 ECA 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.

Net
Proceeds Receivable included in the Statements of Assets, Liabilities and Trust Corpus as of December 31, 2009 are expected to be received by the Trust and distributed to the
Unitholders on March 15, 2010. The December 31, 2008 Net Proceeds Receivable were received and distributed by the Trust on March 13, 2009.

6.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 $615,789 for the year ended December 31, 2009, $755,198 for the year ended December 31, 2008 and $621,663 for the year
ended December 31, 2007. 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 ECA for
overhead expenses. The initial fee

F-11

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Table of Contents

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

6.Related Party Transactions: (Continued)

at
the inception of the Trust was $210,000. The Trustee paid ECA $364,136, $351,824 and $339,924 for overhead expenses for 2009, 2008 and 2007, respectively. Operating Cost Charges included in the
Statements of Distributable Income are paid to ECA.

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, ECA has agreed to make payments under the Gas Purchase Contract to the extent such payments are not made by Eastern Marketing.

7.Subsequent Events:

Management evaluated all activity of the Trust through the date of the filing of these financial statements and concluded that no subsequent events have occurred that would require
recognition in the Financial Statements or disclosure in the Notes to the Financial Statements except as follows:

The
Trust was formed under the Delaware Business Trust Act pursuant to a Trust Agreement (the "Trust Agreement") among Eastern American Energy Corporation, as grantor, Bank of Montreal
Trust Company, as trustee, and Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee"). Until January 1, 2010, Eastern American Energy Corporation was a wholly-owned subsidiary
of Energy Corporation of America. Effective January 1, 2010, Eastern American Energy Corporation was merged
into Energy Corporation of America, with Energy Corporation of America being the surviving corporation. The merger of Eastern American Energy Corporation into its parent Energy Corporation of America
is not expected to have any significant effect on the Trust.

F-12

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Table of Contents

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, Ryder Scott. 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 ECA 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 ECA. 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 ECA 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, 2007 to December 31,
2009:

Royalty NPI

Term NPI

Total NPI(MMcf)

(MMcf)

(MMcf)Balance, January 1, 2007


9,885


4,814


14,699Production


(774
)

(984
)

(1,758
)Revisions of previous estimates


901


(5
)

896Balance, December 31, 2007


10,012


3,825


13,837Production


(707
)

(930
)

(1,637
)Revisions of previous estimates


530


179


709Balance, December 31, 2008


9,835


3,074


12,909Production


(694
)

(911
)

(1,605
)Revisions of previous estimates


(758
)

154


(604
)Balance, December 31, 2009


8,383


2,317


10,700


F-13

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Table of Contents

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

Royalty NPI

Term NPI

Total NPI(MMcf)

(MMcf)

(MMcf)December 31, 2007


10,012


3,825


13,837December 31, 2008


9,835


3,074


12,909December 31, 2009


8,383


2,317


10,700


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, 2009 (in thousands):

Royalty NPI

Term NPI

Total NPIFuture cash inflows

$
61,761

$
15,072

$
76,833Future production taxes


(2,982
)

(644
)

(3,626
)Future production costs


(12,361
)

(1,598
)

(13,959
)Future net cash inflows


46,418


12,830


59,24810% discount factor


(26,918
)

(1,862
)

(28,790
)Standardized measure of discounted future net cash flows

$
19,490

$
10,968

$
30,458


The
following is the standardized measure of discounted future net cash flows as of December 31, 2008 (in thousands):

Royalty NPI

Term NPI

Total NPIFuture cash inflows

$
112,434

$
33,015

$
145,449Future production taxes


(5,079
)

(1,341
)

(6,420
)Future production costs


(13,734
)

(2,417
)

(16,151
)Future net cash inflows


93,621


29,257


122,87810% discount factor


(55,987
)

(5,300
)

(61,287
)Standardized measure of discounted future net cash flows

$
37,634

$
23,957

$
61,591


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


F-14

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Table of Contents

Changes
in Standardized Measure of Discounted Future Net Cash Flows:

The
following schedule reconciles the changes during 2007, 2008 and 2009 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, 2007

$
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

$
58,514Net proceeds to the Trust


(11,548
)

(3,609
)

(15,157
)Revisions of previous estimates


2,529


854


3,383Accretion of discount


3,372


2,479


5,851Net change in price and production costs


5,047


1,570


6,617Other


4,507


(2,124
)

2,383Standardized measure, December 31, 2008

$
37,634

$
23,957

$
61,591Net proceeds to the Trust


(5,881
)

(1,625
)

(7,506
)Revisions of previous estimates


(2,157
)

438


(1,719
)Accretion of discount


3,763


2,396


6,159Net change in price and production costs


(17,593
)

(4,164
)

(21,756
)Other


3,724


(10,034
)

(6,309
)Standardized measure, December 31, 2009

$
19,490

$
10,968

$
30,458




The
following is a summary of royalty income and distributable income per unit by quarter in 2009, 2008 and 2007 (all amounts in thousands except Distributable
income per unit):

2009

Mar 31

June 30

Sept 30

Dec 31

TotalRoyalty Income

$
2,666

$
2,055

$
2,040

$
2,107

$
8,868Distributable Income

$
1,953

$
1,484

$
1,563

$
1,527

$
6,527Distributable Income Per Unit

$
0.3312

$
0.2515

$
0.2648

$
0.2587

$
1.0162




2008

Mar 31

June 30

Sept 30

Dec 31

TotalRoyalty Income

$
3,548

$
4,679

$
4,980

$
3,821

$
17,028Distributable Income

$
2,773

$
3,957

$
4,302

$
3,018

$
14,050Distributable Income Per Unit

$
0.4700

$
0.6706

$
0.7291

$
0.5116

$
2.3813




2007

Mar 31

June 30

Sept 30

Dec 31

TotalRoyalty Income

$
3,565

$
3,855

$
3,694

$
3,547

$
14,661Distributable Income

$
2,832

$
3,144

$
3,084

$
2,947

$
12,007Distributable Income Per Unit

$
0.4800

$
0.5328

$
0.5228

$
0.4995

$
2.0350


F-15

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