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





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, 2011ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934FOR THE TRANSITION PERIOD FROM          TO


Commission file number: 1-11748

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

Delaware(State or other Jurisdiction of
Incorporation or Organization)

36-7034603(I.R.S. Employer
Identification No.)


The Bank of New York 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 February 28, 2012, 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 February 28, 2012, 1,968,350 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, 2011 of $22.99 per unit was approximately $94 million.

Documents
Incorporated By Reference:None





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Table of Contents



TABLE OF CONTENTS



PART I


3Item 1.

Business


3Description of the Trust


3The Net Profits Interests


5The Underlying Properties


11Competition and Markets


15Regulation of Natural Gas


15Health, Safety and Environmental Regulation


15Description of Trust Units and Depositary Units


18Federal Income Tax Matters


22State Tax Considerations


22Available Information


23Item 1A.

Risk Factors


23Item 1B.

Unresolved Staff Comments


27Item 2.

Properties


27Item 3.

Legal Proceedings


27Item 4.

Mine Safety Disclosures


27PART II


28Item 5.

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


28Item 6.

Selected Financial Data


28Item 7.

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


29Item 7A.

Quantitative and Qualitative Disclosures About Market Risk


33Item 8.

Financial Statements and Supplementary Data


34Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


35Item 9A.

Controls and Procedures


35Item 9B.

Other Information


36PART III


37Item 10.

Directors, Executive Officers, and Corporate Goverance


37Item 11.

Executive Compensation


37Item 12.

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


37Item 13.

Certain Relationships and Related Transactions, and Director Independence


38Item 14.

Principal Accounting Fees and Services


38PART IV


39Item 15.

Exhibits, Financial Statement Schedules


39SIGNATURES


40


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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").

The
Trust will sell its assets and liquidate between May 15, 2012 and May 15, 2013 (the "Liquidation Date"). Pursuant to the Trust Agreement, all proceeds of any sale
received by the Trustee after December 31, 2012, and all other receipts of the Trust received after December 31, 2012, will be retained by the Trustee until all remaining Royalty NPI
interests have been sold. Consequently, unitholders will not receive any distribution of any amount from the Trust relating to amounts received by the Trust after December 31, 2012 except for
any final distribution to be made after the sale of the Royalty NPI as described herein. Any final distribution will be subject to the prior payment of all expenses and liabilities of the Trust, and
to the establishment and funding of any reserves the Trustee deems appropriate for contingent liabilities. See "Description of Trust Units and Depository UnitsLiquidation of the Trust."

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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 has not had 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 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

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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 2011 were $108,000. The total of all Trustee fees and Trust administrative expenses for 2011 was $739,133. Such costs could
fluctuate in the future depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and engineering services, and may be materially higher during
2012 and 2013 than they have been in the past as the Trust incurs expenses in connection with the sale of its assets and liquidation in accordance with the Trust Agreement. In addition to such
expenses, in 2011, the Trust paid ECA an overhead reimbursement of $390,072. The overhead reimbursement was established at the inception of the Trust, increases by 3.5% per year, and is payable
quarterly.

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. See "Description of Trust Units and Depositary
UnitsLiquidation of the Trust."

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
Trust is expected to terminate in 2013. See "Description of Trust Units and Depository UnitsLiquidation of 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

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Term NPI.
As of December 31, 2011, 27,415 MMcf of such gas had been produced. Consequently, the Term NPI is expected to terminate on May 15, 2013.

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.

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.

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 2011 was $658,604, for 2010 was $658,604 and for 2009 was $647,917.
As discussed below, the 2011 Operating Cost Charge was decreased during the quarter ended June 30, 2011 as a result of wells sold during the second quarter. 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

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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. Due to the "Overhead Adjustment Index" being -0.7%, the adjustment for the effective time period is 0%. As discussed above, 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%). 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. As a result
of selling wells, the Operating Cost Charge was reduced by $21,629 in the quarter ended June 30, 2011 and this reduction was applicable for the quarters ended September 30, 2011 and
December 31, 2011.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.

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

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obtained
with respect to each of the three months in such quarter, in the manner specified below, and then taking the average of the prices determined for each of such three months. The price
determined for any month of such quarter is equal to the average of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in The Wall Street Journal,for such contracts which expired in each of the five months prior to such month, (ii) the final settlement price per
MMBtu for Henry Hub Gas Futures Contracts, as reported inThe Wall Street Journal,for such contracts which expire during such month and
(iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures Contracts determined as of the contract settlement date for such month, as reported inThe Wall
Street Journal,for such contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to
be delivered to the Henry Hub, which is traded on the New York Mercantile Exchange.

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

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

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

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Distributions and Income Computations

The Trustee determines for each quarter the amount of cash available for distribution to holders of Depositary Units and the Trust
Units evidenced thereby. Such amount (the "Quarterly Distribution Amount") is equal to the excess, if any, of (i) the cash that the Trust receives on or before the tenth day of the third month
after the end of each calendar quarter ending before the Trust is dissolved and that is attributable to production from the Net Profits Interest held by the Trust during that calendar quarter, plus,
with certain exceptions, any other cash receipts of the Trust during such quarter, over (ii) the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by
the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. Quarterly Distribution Amounts per unit for each of the quarters in
2011 were $0.1784, $0.2689, $0.2427 and $0.1597, 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 generally 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"). The Trust will sell its assets and liquidate between May 15,
2012 and May 15, 2013. Pursuant to the Trust Agreement, all proceeds of any sale received by the Trustee after December 31, 2012, and all other receipts of the Trust received after
December 31,
2012, will be retained by the Trustee until all remaining Royalty NPI interests have been sold. Consequently, Unitholders will not receive any distribution of any amount from the Trust relating to
amounts received by the Trust after December 31, 2012 except for any final distribution to be made after the sale of the Royalty NPI as described herein. Any final distribution will be subject
to the prior payment of all expenses and liabilities of the Trust, and to the establishment and funding of any reserves the Trustee deems appropriate for contingent liabilities. See "Description of
Trust Units and Depository UnitsLiquidation of the Trust."

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

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

Sale and Abandonment of Underlying Properties; Sale of Royalty NPI

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,

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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.

ECA
may sell the Underlying Properties, subject to and burdened by the Net Profits Interests, without the consent of the Trust or the Unitholders. Any releases by the Trust are
conditioned upon the Trust receiving an amount equal to the fair value (as defined in the Trust Agreement) to the Trust of its Net Profits Interests (taking into account the relevant market conditions
and factors existing at the time of the sale. Any proceeds paid to the Trust are distributable to Unitholders for the quarter in which they are received

During
the first half of 2011, Energy Corporation of America entered into two separate Purchase and Sale Agreements to sell certain assets in which the Trust owned a Net Profits Interest
to unrelated third parties. ECA finalized the sale of the assets, as described in the Purchase and Sale Agreements, in the quarter ended June 30, 2011. ECA received sale proceeds for the wells
in the amount of $588,911. The Trust's share of the sales proceeds was $181,928 and was included in the Distributable Income of the Trust during the quarter ended June 30, 2011. No other sale
of assets in which the Trust owned a Net Profits Interest occurred in 2011.

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 Term NPI will expire by its terms no later than May 15, 2013, and the Trust will
not realize any further value from the Term NPI after such date.

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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, 2011, such properties consisted of 587 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, 2011, proved developed reserves
attributable to the Net Profits Interests (reflecting quantities of gas free of future costs and expenses based on estimated prices) were approximately 8,100 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.

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Reserves

Proved Reserves of Underlying Properties and Net Profits Interests.The following table sets forth, as of December 31, 2011,
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, 2011 prepared by Ryder Scott Company (the "Reserve Report".) Proved reserve quantities attributable to the Net Profits
Interests are calculated by subtracting an amount of gas sufficient, if sold at the
prices used in preparing the reserve estimates, to pay the future estimated costs and expenses deducted in the calculation of Net Proceeds. Accordingly, the reserves attributable to the Net Profits
Interests reflect quantities of gas that are free of future costs or expenses if the price and cost assumptions set forth in the Reserve Report occur. A decrease in the price assumption, or an
increase in the cost assumption used in the Reserve Report would reduce the estimates of proved reserves, future net revenues and discounted future net revenues, set forth herein and in the Reserve
Report. The Term NPI excludes production beyond the earlier of May 15, 2013 or such time as 41,683 MMcf 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)


25,930


0


25,930

$
93,468

$
39,445Net Profits Interests:Royalty NPI


7,203


0


7,203

$
35,472

$
15,163Term NPI


897


0


897


4,417


4,117Total


8,100


0


8,100

$
39,889

$
19,280


(1)Reserve
volumes and estimated future net revenues for Underlying Properties reflect volumes and revenues distributable to ECA's entire net revenue interest
with respect to the Underlying Properties.(2)The
effects of depreciation, depletion and federal income tax have not been taken into account in estimating future net revenues. Estimated future net
revenues and discounted estimated future net revenues are not intended, and should not be interpreted, as representing the fair market value for the estimated reserves.


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.

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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 December 23, 2011 (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, 2011. 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 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, served as a Managing Senior Vice President and also as a member of the Board of Directors during the period covered by this report, 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
served 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 by Dr. John Lee 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 19, 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 December 23, 2011 and has an effective date of December 31, 2011. 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, 2011 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

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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 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 Trust believes 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.

Internal Controls.Ryder Scott prepared its report as described above in accordance with appropriate engineering, geologic, and
evaluation principles
and techniques that are in accordance with practices generally accepted in the petroleum industry, and definitions and guidelines established by the SEC. These reserves, estimation methods and
techniques are widely taught in university petroleum curricula and throughout the industry's ongoing training programs. Although these appropriate engineering, geologic, and evaluation principles and
techniques that are in accordance with practices generally accepted in the petroleum industry are based upon established scientific concepts, the application of
such principles involves extensive judgment and is subject to changes in existing knowledge and technology, economic conditions and applicable statutory and regulatory provisions. The same industry
wide applied techniques are used in determining estimated reserve quantities. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding
qualifications, independence, objectivity and confidentiality set forth in the Society of Petroleum Engineering Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information.
ECA has advised the Trust that it maintains adequate controls over the underlying data it provides to Ryder Scott, which is designed to result in accurate and reliable data in compliance with
applicable regulations and guidance. The data ECA furnishes to Ryder Scott is reviewed by staff reservoir engineers and geoscientists before review by the Reservoir Engineering Manager and finally the
Senior Vice President. These individuals consult regularly with Ryder Scott during Ryder Scott's reserve estimation process to review properties, assumptions, and any new data available. ECA's
Reservoir Engineer Manager has a Bachelor of Science in Petroleum Engineering. He has over five years of oil and gas industry experience in reservoir Engineering. ECA's Senior Vice President is the
primary technical person responsible for overseeing the data reporting process. This individual has a Bachelor of Science degree in Chemical Engineering with Masters of Petroleum Engineering
coursework along with a Master of Business Administration degree. He has worked in drilling, completions, production, and reservoir engineering along with acquisitions during his career and is a
member of the Society of Petroleum Engineers. He has over eight years of experience in reserve evaluation.

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.

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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."

The
natural gas industry is highly competitive. ECA competes with major oil and gas companies and independent oil and gas companies for oil and gas leases, equipment, personnel and
markets for the sale of natural gas. Many of these competitors are financially stronger than ECA, but even financially troubled competitors can affect the market because they may need to sell natural
gas regardless of price to attempt to maintain cash flow. The Trust is subject to the same competitive conditions as ECA and other companies in the natural gas industry.

Natural
gas competes with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the
availability or price of natural gas or other forms of energy, as well as business conditions, conservation, legislation,
regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for natural gas.

Future
price fluctuations for natural gas will directly affect Trust distributions, estimates of reserves attributable to the Trust's interests, and estimated and actual future net
revenues to the Trust. In view of the many uncertainties that affect the supply and demand for natural gas, neither the Trust nor ECA can make reliable predictions of future gas supply or demand,
future gas prices or the effect of future gas prices on the Trust.

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

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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 are expected to 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 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 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 strict,
joint and several liability, regardless of fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for 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 obtain pre-approval for, forego or modify construction or operation of certain air emission
sources.

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On
December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the
environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. These findings allow the EPA to adopt and implement
regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. These findings allow the EPA to adopt and implement regulations that would restrict emissions
of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that could trigger permit review for GHG emissions from certain stationary sources. The EPA
has also issued regulations that require the establishment and reporting of an inventory of GHG emissions from specified stationary sources, including certain onshore oil and natural gas exploration,
development and production facilities. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG gases from, equipment and operations could
require ECA to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas it produces.

More
than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories
and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is
possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.

Endangered Species Act.The federal Endangered Species Act, as amended ("ESA"), restricts activities that may affect endangered and
threatened
species or their habitats. The designation of previously unidentified endangered or threatened species could cause ECA to incur additional costs or become subject to operating restrictions or bans in
the affected areas.

Water Discharges.The Federal Water Pollution Control Act, as amended ("Clean Water Act"), and analogous state laws impose restrictions
and strict
controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or
waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by EPA or the analogous state agency. The
Pennsylvania Department of Environmental Protection has adopted a new permitting policy concerning surface water discharges from wastewater treatment facilities handling flowback fluids and produced
waters from oil and gas well sites that could result in increased requirements for treatment of these fluids and limitations on their discharge to receiving waters. If ECA or the operator of the
Underlying Properties is unable to remove and dispose of water at a reasonable cost and within applicable environmental rules, the ability to produce gas commercially and in commercial quantities from
the Underlying Properties could be impaired.

Spill
prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable
waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws, including in Pennsylvania and West Virginia, require individual
permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

State regulation.Pennsylvania regulates the drilling for, and the production, gathering and sale of, natural gas, including imposing
requirements
for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells, production rates and the prevention of waste of natural gas resources. The Pennsylvania
Environmental Quality Board has proposed amendments to Pennsylvania's oil and gas regulations to update existing requirements regarding the drilling, casing, cementing, testing, monitoring and
plugging of oil and gas wells, and the protection of water supplies,

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that,
if adopted in their proposed form, could require ECA to incur increased operating costs. West Virginia's legislature is considering similar changes to its laws regulating oil and gas
development.

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

DESCRIPTION OF TRUST UNITS AND DEPOSITARY UNITS

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

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delivering
written notice of such transfer jointly to the Depositary and the Trustee together with proper documentation necessary to transfer the requisite Treasury Obligations into the name of the
Depositary.

Distributions and Income Computations

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

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

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; provided, however, that any Depositary Unit from which the related Treasury Obligations have been withdrawn shall not entitle the holder to any portion of the proceeds of
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

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notice
will constitute a demand that such holder dispose of his Depositary Units or withdrawn Trust Units within 30 days. If any holder fails to dispose of his Depositary Units or withdrawn
Trust Units in accordance with such notice, cash distributions on such units are subject to suspension. In the event a holder fails to dispose of Depositary Units in accordance with such notice, the
Depositary may cancel such holder's Depositary Units and reissue them in the name of the Trustee, whereupon the Trustee will use its reasonable efforts to sell the Depositary Units and remit the net
sale proceeds to such holder. In the case of Trust Units withdrawn from deposit with the Depositary, the Trustee shall redeem such Trust Units not divested in accordance with such notice, for a cash
price equal to the then-current market price of the Depositary Units less the then-current over-the-counter bid price of the related, withdrawn Treasury
Obligations. The redemption price will be paid out in quarterly installments limited to the amount that otherwise would have been distributed in respect of such redeemed Trust Units.

Liability of Unitholders

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

Liquidation of the Trust

The Trust will be liquidated and the Royalty NPI will be sold prior to the Liquidation Date, which is expected to occur in 2013.
Unitholders of record as of the record date for the final quarter of the Trust's existence will be entitled to receive a terminating distribution with respect to each Depositary Unit equal to a pro
rata portion of the net proceeds from the sale of the Royalty NPI (to the extent not previously distributed) and a pro rata portion of the proceeds from the matured Treasury Obligations (to the extent
not previously withdrawn). 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. The Term NPI will expire by its terms no later than May 15, 2013, and the Trust will not realize any further value from the Term NPI after such date.

Pursuant
to the Trust Agreement, all proceeds of any sale received by the Trustee after December 31, 2012, and all other receipts of the Trust received after December 31,
2012, will be retained by the Trustee until all remaining Royalty NPI interests have been sold. Consequently, Unitholders will not receive any distribution of any amount from the Trust relating to
amounts received by the Trust after December 31, 2012 except for any final distribution to be made after the sale of the Royalty NPI described herein. Subject to the payment of all expenses and
liabilities of the Trust, and subject to the creation and funding of cash reserves in such amounts as the Trustee in its discretion deems appropriate for contingent liabilities, all amounts then held
by the Trust will be distributed to Unitholders of record as of the record date for the final quarter of the Trust's existence.

Subject
to ECA's rights of first refusal and other provisions of the Trust Agreement described herein, the Trustee is required to use its best efforts to sell the Royalty NPI for cash,
effective after May 15, 2012 and prior to May 15, 2013.

If
the Trustee has not sold the Royalty NPI on or prior to September 30, 2012, the Trustee is required to engage an independent appraiser (at the expense of the Trust) to appraise
the fair value of the NPI as of September 30, 2012, and to deliver a copy of such appraisal to ECA by November 15, 2012. ECA will then be entitled but not obligated to purchase the
Royalty NPI for cash at the appraised value (less the aggregate amount of distributions made to the Trust from the Royalty NPI since September 30, 2012) by delivery of a notice to the Trustee
given within ten business days from ECA's receipt of the appraiser's report. If ECA elects not to purchase the Royalty NPI, the Trustee is required to take all reasonable actions within its discretion
necessary to arrange for an unreserved

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auction
or sealed bid sale of the Royalty NPI to be held on March 1, 2013, and to sell the Royalty NPI to the highest cash bidder at the auction or sale.

The
Trustee will mail notice of any sale by auction or sealed bid to each Trust Unitholder at his or her address as it appears in the records of the Trustee at least 60 days prior
to any such sale. However, no approval of the Trust Unitholders will be required or sought prior to any such sale of the Royalty NPI or any portion thereof as described herein.

In
addition to ECA's purchase right at an appraised fair value as described above, ECA has the right under the Trust Agreement to purchase any or all of the Royalty NPI from the Trust on
the same price and terms as those offered by any person in any proposed sale. Further, in the event of a proposed disposition by auction or sealed bid, ECA has an additional right to purchase the
Royalty NPI to be sold as described below.

Except
for proposed dispositions by auction or sealed bid, the Trustee is required to give written notice to ECA at least 20 business days prior to the date of any proposed disposition
setting forth in reasonable detail a description of the Royalty NPI to be sold, and the proposed price and terms of such disposition. ECA may exercise its right to purchase the Royalty NPI to be sold
by giving written notice to the Trustee no later than ten business days from the date of receipt of such notice.

In
the event the Trustee gives notice of a proposed disposition of all or a portion of the Royalty NPI by auction or sealed bid, the Trustee shall prior to such auction or bid, unless
the right of first refusal is waived by ECA, engage (at the expense of the Trust) an independent appraiser to appraise the fair value (as of the date of such notice) of the portion of the Royalty NPI
proposed to be sold. Upon receipt of the appraisal, ECA may exercise its option to acquire the portion of the Royalty NPI proposed to be sold for cash in the amount of the appraised value (less the
aggregate amount of distributions made to the Trust from that portion of the Royalty NPI since the date of the appraised value) by delivery of a written election notice to the Trustee within ten
business days from the date of receipt by ECA of the independent appraiser's report.

In
the event the Trustee gives notice of a proposed disposition of all or a portion of the Royalty NPI by auction or sealed bid, and ECA does not exercise its option to acquire the
portion of the Royalty NPI proposed to be sold, ECA could, but would not be required to, bid for the Royalty NPI to be sold in the auction or sealed bid process. No assurance can be given that ECA
would make a bid in any such process. However, in the event that ECA were to bid in any such process and were the top bidder, ECA would be entitled to purchase the Royalty NPI to be sold in the
auction or sealed bid process. Any such purchase pursuant to the auction or sealed bid process by ECA or a third party could be at a price lower than fair value.

As
used in the foregoing discussion, the term "fair value" has the meaning ascribed to it in the Trust Agreement, which means an amount which could reasonably be expected to be obtained
from the sale of the asset to a party which is not an affiliate of either ECA or the Trust on an arms'-length negotiated basis, taking into account relevant market conditions and factors existing at
the time of the proposed sale.

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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.

Widely Held Fixed Investment Trust Reporting Information

The Trustee assumes that some Depositary units and the underlying Trust 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 customer in street name, referred to herein collectively as "middlemen").
Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust ("WHFIT") for U.S. Federal
income tax purposes. Accordingly, the Trust will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a
WHFIT. The representative of the Trust that will provide the required information is The Bank of New York Mellon Trust Company, N.A., and the contact information for the representative is as follows:



Available Trust Tax Information

In compliance with the reporting requirements for WHFITs and the dissemination of trust tax reporting information, the trustee provides
a generic tax information reporting booklet that is intended to be used only to assist unitholders in the preparation of their 2011 federal and state income tax returns. This tax information booklet
can be obtained atwww.businesswire.com/cnn/ngt.htm.

Notwithstanding
the foregoing, the middlemen holding the Depositary Units and the underlying Trust 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 and the underlying Trust Units, including the issuance of IRS
Forms 1099 and certain written tax information statements to the investor.

Each
Unitholder should consult his or her own 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.

The net proceeds of the sale of the Trust's Royalty NPI are unpredictable.

The Trustee is required by the Trust Agreement to sell all of the Royalty NPI after May 15, 2012 and prior to May 15,
2013. 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. The sale price of
the Royalty NPI will depend on a wide variety of factors over which neither the Trust nor the Trustee has or will have any control, including ECA's preemptive rights to purchase the Royalty NPI as set
forth in the Trust Agreement, the nature of the Royalty NPI as a non-operated interest, natural gas prices and the expectations of potential purchasers regarding future natural gas prices,
conditions in the U.S. oil and gas divestiture markets generally, conditions in the credit markets and expectations of market participants regarding credit pricing and availability, interest rates and
market expectations regarding interest rates, developments and expectations regarding developments in shale gas and other natural gas exploration and production developments in the Marcellus Shale
region and elsewhere in the Appalachian Basin, and in the United States and world generally, and all other factors relevant to a potential purchaser's evaluation of the attractiveness of the Royalty
NPI. Further, because the Gas Purchase Contract will terminate upon the termination of the Trust, the fair value of the Royalty NPI may be different after the termination of the Trust than it has been
during the existence of the Trust. The Term NPI will expire by its terms no later than May 15, 2013, and the Trust will not receive any payment for the Term NPI after its expiration.

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.

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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 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

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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 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

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natural
gas, economic conditions and upon financial, business and other factors, many of which are beyond the control of ECA.

The tax treatment of an investment in Trust Units or Depositary Units could be affected by recent and potential legislative changes, possibly on a retroactive basis.

The recently enacted Health Care and Education Affordability Reconciliation Act of 2010 includes a provision that, in taxable years
beginning after December 31, 2012, subjects an individual having modified adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to a "Medicare
tax" equal generally to 3.8% of the lesser of such excess or the individual's net investment income, which appears to include royalty income and interest income, if any, derived from the Trust Units
or Depositary Units as well as any net gain from the disposition of Trust Units or Depositary Units. In addition, absent new legislation extending the current rates, beginning January 1, 2013,
the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these
rates are subject to change by new legislation at any time.

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.Mine Safety Disclosures.

Not applicable.

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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, 2011 were as follows:

Quarter

High

Low

Distributions
Paid2010:First (to March 31, 2010)

$
23.91

$
23.50

$
0.2217Second (to June 30, 2010)

$
23.66

$
22.03

$
0.2592Third (to September 30, 2010)

$
23.09

$
22.05

$
0.2625Fourth (to December 31, 2010)

$
23.90

$
22.20

$
0.22782011:First (to March 31, 2011)

$
24.11

$
22.76

$
0.1784Second (to June 30, 2011)

$
24.00

$
22.85

$
0.2689Third (to September 30, 2011)

$
23.50

$
22.74

$
0.2427Fourth (to December 31, 2011)

$
23.98

$
23.00

$
0.1597


At
February 28, 2012, the 5,900,000 Depositary Units outstanding were held by approximately 289 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, 2011 to December 31, 2011 were $998.40 and
$973.80, respectively. The closing price on December 31, 2011 was $997.10 per $1,000 face amount.

During
the fourth quarter of 2011, 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,
2011

December 31,
2010

December 31,
2009

December 31,
2008

December 31,
2007Royalty Income

$
7,322,590

$
8,172,392

$
8,868,114

$
17,028,373

$
14,660,909Distributable Income

$
5,263,272

$
5,730,157

$
6,526,597

$
14,049,648

$
12,006,605Distribution Amount

$
5,013,272

$
5,730,157

$
6,526,597

$
14,049,648

$
12,506,605Distributable Income per unit

$
0.8921

$
0.9712

$
1.1062

$
2.3813

$
2.0350Distribution Amount per unit

$
0.8497

$
0.9712

$
1.1062

$
2.3813

$
2.1198Total assets at year end

$
13,578,463

$
15,991,130

$
18,635,014

$
22,570,038

$
24,953,135


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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.

Under
the Gas Purchase Contract, Eastern Marketing, a wholly-owned subsidiary of ECA, 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 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 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 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 Shields #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.

During
the first half of 2011, ECA entered into two separate Purchase and Sale Agreements to sell certain assets to unrelated third parties in which the Trust owned a Net Profits
Interest. As of January 1, 2010 ECA 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. ECA finalized the sale of the assets, as described in the Purchase and Sale Agreements, in the quarter ended June 30,
2011. ECA received sale proceeds for

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the
wells in the amount of $588,911. The Trust's share of the sales proceeds was $181,928 and was included in the Distributable Income of the Trust during the quarter ended June 30, 2011.

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 2011 was $739,133, including the Trustee's fee of $108,000. In addition to such expenses, in 2011, the
Trust paid ECA an overhead reimbursement of $390,072. 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 and may be materially higher during 2012 and 2013 than they have been in
the past as the Trust incurs expenses in connection with the sale of its assets and liquidation in accordance with the Trust Agreement..

On
December 8, 2004, the Trust announced approval by the Trust Unitholders of a proposal to elect JPMorgan Chase to serve as successor trustee of the Trust upon the effective date
of the resignation of The Bank of New York as trustee of and depositary for the Trust and to amend the Trust Agreement to change the compensation of the Trustee. The resignation of The Bank of New
York took effect on January 1, 2005. As successor Trustee, JPMorgan Chase received annual compensation of $108,000 plus fees and expenses. Effective October 2, 2006, The Bank of New York
Trust Company, N.A. (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.

The
Trust will be liquidated and the Royalty NPI will be sold prior to the Liquidation Date, which is expected to occur in 2013. Pursuant to the Trust Agreement, all proceeds of any sale
received by the Trustee after December 31, 2012, and all other receipts of the Trust received after December 31, 2012, will be retained by the Trustee until all remaining Royalty NPI
interests have been sold. Consequently, Unitholders will not receive any distribution of any amount from the Trust relating to amounts received by the Trust after December 31, 2012 except for
any final distribution to be made after the sale of the Royalty NPI as described herein. 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; provided, however, that any Depositary Unit from which the related Treasury Obligations have been withdrawn shall not entitle
the holder to any portion of the proceeds of 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.

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

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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 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.

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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, 2011. At December 31, 2011, the Trust had General and Administrative Expenses Payable of $206,150 and
Distributions Payable of $942,100.

Results of Operations

2011 Compared with 2010

The
Trust's Distributable Income was $5,263,272 for the year ended December 31, 2011 as compared to $5,730,157 for the year ended December 31,
2010. This decrease was due to a decrease in Royalty Income for the year ended December 31, 2011 ($7,322,590) as compared to the year ended December 31, 2010 ($8,172,392). The decrease
was due to a decrease in production of gas attributable to the Net Profits Interests for the year ended December 31, 2011 (1,487 Mmcf) as compared to the year ended December 31, 2010
(1,531 Mmcf). The decline in production is primarily attributable to natural production declines and sale of wells. The decrease was also partially due to a
decrease in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($4.925 per Mcf for the year ended December 31, 2011 as compared to $5.343 per Mcf for the
year ended December 31, 2010). Taxes on Production and Property were $518,355 for the year ended December 31, 2011 as compared to $627,719 for the year ended December 31, 2010.
The decrease in taxes is due directly to the decrease in Royalty Income as discussed above. Trust General and Administrative Expenses were $1,129,205 for the year ended December 31, 2011 as
compared to $1,155,944 for the year ended December 31, 2010. 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 $2,325,766 for the year ended December 31, 2011 as compared to $2,388,780 for the year ended December 31, 2010.
This decrease was due to the decrease in production for the year ended December 31, 2011. This decrease was partially offset due to the increase in the depletion rate to $1.5638 for the year
ended December 31, 2011 from $1.5603 for the year ended December 31, 2010.

The
average price payable to the Trust for gas production attributable to the Net Profits Interests was $4.925 per Mcf for the year ended December 31, 2011 and $5.343 per Mcf for
the year ended December 31, 2010. The price per Mcf was lower for the year ended December 31, 2011 than for the year ended December 31, 2010 due to a decrease in the average spot
market price for gas delivered at the Henry Hub near Henry, Louisiana ($4.177 per Dth for the year ended December 31, 2011 as compared to $4.557 per Dth for the year ended December 31,
2010).

2010 Compared with 2009

The
Trust's Distributable Income was $5,730,157 for the year ended December 31, 2010 as compared to $6,526,597 for the year ended December 31,
2009. This decrease was due to a decrease in Royalty Income for the year ended December 31, 2010 ($8,172,392) as compared to the year ended December 31, 2009 ($8,868,114). The decrease
was due to a decrease in production of gas attributable to the Net Profits Interests for the year ended December 31, 2010 (1,531 Mmcf) as compared to the year ended December 31, 2009
(1,604 Mmcf). The decline in production is primarily attributable to natural production declines. The decrease was also partially due to a decrease in the average price payable to the Trust under the
Gas Purchase Contract as discussed below ($5.343 per Mcf for the year ended December 31, 2010 as compared to $5.534 per Mcf for the year ended December 31, 2009). Taxes on Production and
Property were $627,719 for the year ended December 31, 2010 as compared to $676,110 for the year ended December 31, 2009. The decrease in taxes is due directly to the

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decrease
in Royalty Income as discussed above. Trust General and Administrative Expenses were $1,155,944 for the year ended December 31, 2010 as compared to $979,925 for the year ended
December 31, 2009. The increase in General and Administrative Expenses was due primarily to an increase in professional fees incurred.

Amortization
of Net Profits Interests in Gas Properties was $2,388,780 for the year ended December 31, 2010 as compared to $2,370,117 for the year ended December 31, 2009.
This increase was due to the increase in the depletion rate to $1.5603 for the year ended December 31, 2010 from $1.4769 for the year ended December 31, 2009.

The
average price payable to the Trust for gas production attributable to the Net Profits Interests was $5.343 per Mcf for the year ended December 31, 2010 and $5.534 per Mcf for
the year ended December 31, 2009. The price per Mcf was lower for the year ended December 31, 2010 than for the year ended December 31, 2009 due to a decrease in the average spot
market price for gas delivered at the Henry Hub near Henry, Louisiana ($4.557 per Dth for the year ended December 31, 2010 as compared to $4.731 per Dth for the year ended December 31,
2009).

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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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, 2011 and 2010


F-4Statements of Distributable Income for the years ended December 31, 2011, 2010 and 2009


F-5Statements of Changes in Trust Corpus for the years ended December 31, 2011, 2010 and 2009


F-6Notes to Financial Statements


F-7Supplemental Reserve Information (Unaudited)


F-13


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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.

As
of December 31, 2011, the Trustee carried out an evaluation of the Trustee's disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded
that the disclosure controls and procedures are effective.

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



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.

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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, 2011. The effectiveness of the Trust's internal control over financial
reporting as of December 31, 2011 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.

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 that occurred
during the Trust's last fiscal quarter, 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. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning, the internal
control over financial reporting of ECA.

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, 2011,
December 31, 2010 and December 31, 2009, The Bank of New York Mellon Trust Company, N.A., as Trustee, received $108,000 annually, as Trustee fees and $631,133, $671,064 and $507,789,
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.



Name

Number of
Shares

Percent of
ClassSoftVest, LP.(1)
400 Pine Street
Suite 1010
Abilene, TX 79601


300,000


5.08
%


(1)Reference
is hereby made to the Schedule 13G/A filed by SoftVest, LP on January 14, 2011 for information regarding the ownership of the
reporting person.


(b)   Security
Ownership of Management.



(c)   Changes
in Control.



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



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

The Trust has no directors. Since January 1, 2011 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. However, as described in this report, the Trust Agreement requires the Trustee to use
its best efforts to sell the Royalty NPI for cash, effective after May 15, 2012 and prior to May 15, 2013, and ECA has rights of first refusal and other rights to purchase the Royalty
NPI as set forth in Trust Agreement. See "Description of Trust Units and Depository UnitsLiquidation of the Trust."

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 $150,000 in 2011 and $194,645 in 2010.

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 $119,300 in 2011 and $115,650 in 2010.

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.

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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, 2011 and 2010

F-4Statements of Distributable Income for the years ended December 31, 2011, 2010 and 2009

F-5Statements of Changes in Trust Corpus for the years ended December 31, 2011, 2010 and 2009

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 December 23, 2011


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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 9th day of March, 2012.

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.

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ANNEX A

LOGO

December 23,
2011

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,
2011. 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
properties evaluated by Ryder Scott represent 100 percent of the total net proved gas reserves of Eastern American Natural Gas Trust as of December 31, 2011.

The
estimated reserves and future net income amounts presented in this report, as of December 31, 2011 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, 2011Proved Net Developed

Gas
(MMCF)

Estimated
Future Net
Cash Inflows
(M$)

Present
Value
At 10%
(M$)Royalty NPI


7,203


35,472


15,163Term NPI


897


4,417


4,117Total


8,100


39,889


19,280


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, 2011 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

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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 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.

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, 2011 from this report are presented in the following table:

As of December 31, 2011Total Proved

Royalty
NPI

Term
NPI

TotalsFuture Cash Inflows (M$)


35,472


4,417


39,889Future CostsProduction (M$)


0


0


0Development (M$)


0


0


0Total Costs (M$)

$
0


0


0Future Net Cash InflowsBefore Income Tax (M$)


35,472


4,417


39,889Present Value at 10%Before Income Tax (M$)


15,163


4,117


19,280




As of December 31, 2011Royalty
NPI

Term
NPI

TotalsProved Net Developed ReservesGas (MMCF)


7,203


897


8,100Proved Net Undeveloped ReservesGas (MMCF)


0


0


0Total Proved Net ReservesGas (MMCF)


7,203


897


8,100


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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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, 2011
SEC Parameters

ProvedTotal
ProvedNet Remaining Reserves

Developed

UndevelopedGas-MMCF


25,930


0


25,930


The
estimated future net income associated with the foregoing volumes and the 10 percent discounted estimated future net income was $93,468,186 and $39,444,532, 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.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulations
Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "Petroleum Reserves Definitions" is included as an attachment to this
report.

The
various proved reserve status categories are defined under the attachment entitled "Petroleum Reserves Definitions" in this report.

No
attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in
operations as reserves.

Reserves
are "estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects
to known accumulations." All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the
estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and
the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are
less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their
recoverability. At Eastern American Natural Gas Trust's request, this report addresses only the proved reserves attributable to the properties evaluated herein.

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. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for
proved reserves as a "high degree of confidence that the quantities will be recovered."

Proved
reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states
that "as changes due to increased availability of geoscience (geological, geophysical, and geochemical),

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engineering,
and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease." Moreover,
estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies and economic risks. Therefore, the proved reserves included in this report
are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated
amounts. As stated earlier in this report, the Trust owns a 90 percent net profits in the subject properties. Moreover, due to the nature of the Net Profits Interest, a change in the future
costs, or prices different from those projected herein may result in a change in the computed reserves and the Net Proceeds to the Trust even if there are no revisions or additions to the gross
reserves attributed to the property.

ECA's
operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to production practices,
environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations
and policies may
cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ from the estimated quantities.

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.

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.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of
recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the
Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain
generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and
(3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method
or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the
established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In
many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate,
irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of
the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve
category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that

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addresses
the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are
much more likely than not to be achieved." The SEC states that "probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with
proved reserves, are as likely as not to be recovered." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total
quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reserve category must meet
the SEC definitions as noted above.

Estimates
of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore,
estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of
regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The
proved reserves for the properties included herein are all proved producing and were estimated by performance methods. The performance method utilized was decline curve analysis
which utilized extrapolations of historical production data available through August, 2011. The data utilized in this analysis were furnished to Ryder Scott by ECA and were considered sufficient for
the purpose thereof.

To
estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of
reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of
future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on
existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received
for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance
with rules adopted by the SEC, omitted from consideration in making this evaluation.

ECA
has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In
preparing our forecast of future proved production and income, we have relied upon data furnished by ECA with respect to property interests owned, production from examined wells, normal direct costs
of operating the wells or leases, ad valorem and production taxes, product prices based on the SEC regulations, adjustments or differentials to product prices. Ryder Scott reviewed such factual data
for its reasonableness; however, we have not conducted an independent verification of the data furnished by ECA. We consider the
factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In
summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures
that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and
Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein
collectively as the "SEC Regulations." In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC
regulations.

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Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data.

The
future production rates from wells currently on production may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating
conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by
regulatory bodies.

Hydrocarbon Prices

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 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 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, 2011 as $4.925 per Mcf, utilizing $4.177 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.

Costs

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.

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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 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

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set
forth in the SEC regulations and intended
for public disclosure as an exhibit in filings made with the SEC by Eastern American Natural Gas Trust.

We
have provided Eastern American Natural Gas Trust with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital
version included in filings made by Eastern American Natural Gas Trust and the original signed report letter, the original signed report letter shall control and supersede the digital version.

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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-1580GRAPHICLarry T. Nelms P. E. Managing Senior Vice PresidentGRAPHIC


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EASTERN AMERICAN NATURAL GAS TRUST



FINANCIAL
STATEMENTS

as
of December 31, 2011 and 2010
and for the years ended
December 31, 2011, 2010 and 2009

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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, 2011 and 2010, 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, 2011. We also have audited the Trust's
internal control over financial reporting as of December 31, 2011, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Trustee is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment
of the effectiveness of internal control over financial reporting, included in the Trustee's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is
to express opinions on
these financial statements and on the Trust's internal control over financial reporting based on our integrated audits.

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

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

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

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

In
our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Trust at December 31, 2011 and 2010, and the
distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2011, on the

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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, 2011,
based on criteria established in Internal ControlIntegrated Framework issued by COSO.

/s/
PricewaterhouseCoopers LLP

Pittsburgh,
Pennsylvania
March 9, 2012

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EASTERN AMERICAN NATURAL GAS TRUST        STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS        as of December 31, 2011 and 2010

2011

2010Assets:Cash

$
122,740

$
105,531Net Proceeds Receivable


1,475,510


1,579,620Net Profits Interests in Gas Properties


93,162,180


93,162,180Accumulated Amortization


(81,181,967
)

(78,856,201
)11,980,213


14,305,979Total Assets

$
13,578,463

$
15,991,130Liabilities and Trust Corpus:Trust General and Administrative Expenses Payable

$
206,150

$
141,127Distributions Payable


942,100


1,344,024Trust Corpus (5,900,000 units authorized and outstanding)


12,430,213


14,505,979Total Liabilities and Trust Corpus

$
13,578,463

$
15,991,130




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

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EASTERN AMERICAN NATURAL GAS TRUST        STATEMENTS OF DISTRIBUTABLE INCOME        for the years ended  December 31, 2011, 2010 and 2009

2011

2010

2009Royalty Income

$
7,322,590

$
8,172,392

$
8,868,114Operating Expenses:Taxes on Production and Property


518,355


627,719


676,110Operating Cost Charges


593,717


658,604


685,529Total Operating Expenses


1,112,072


1,286,323


1,361,639Net Proceeds to the Trust


6,210,518


6,886,069


7,506,475General and Administrative Expenses


1,129,205


1,155,944


979,925Interest Income


31


32


47Cash Proceeds on Sale of Net Profit Interests


181,928





Distributable Income


5,263,272


5,730,157


6,526,597Cash Reserve Refunded (Withheld)


(250,000
)




Distribution Amount

$
5,013,272

$
5,730,157

$
6,526,597Distributable Income Per Unit (5,900,000 units authorized and outstanding)

$
0.8921

$
0.9712

$
1.1062Distribution Amount Per Unit (5,900,000 units authorized and outstanding)

$
0.8497

$
0.9712

$
1.1062




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

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EASTERN AMERICAN NATURAL GAS TRUST        STATEMENTS OF CHANGES IN TRUST CORPUS        for the years ended  December 31, 2011, 2010 and 2009

2011

2010

2009Trust Corpus, Beginning of Period

$
14,505,979

$
16,894,759

$
19,264,876Distributable Income


5,263,272


5,730,157


6,526,597Distributions Paid or Payable to Unitholders


(5,013,272
)

(5,730,157
)

(6,526,597
)Amortization of Net Profits Interests in Gas Properties


(2,325,766
)

(2,388,780
)

(2,370,117
)Trust Corpus, End of Period

$
12,430,213

$
14,505,979

$
16,894,759




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

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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. 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 did not have any significant effect on the Trust.

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 258 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, 2011, 27,415 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.

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

1. Organization of the Trust: (Continued)

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.

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.

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

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 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, 2011.

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.

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EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

2. Significant Accounting Policies: (Continued)

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
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:

Recent pronouncements issued by the FASB or other authoritative accounting standards groups with future effective dates are either not applicable or are not expected to be significant to
the Trust's financial statements.

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

F-10

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Table of Contents

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

4. Income Taxes: (Continued)

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, 2011 are expected to be received by the Trust and distributed to the
Unitholders on March 15, 2012. The December 31, 2010 Net Proceeds Receivable were received and distributed by the Trust on March 15, 2011.

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 $739,133 for the year ended December 31, 2011, $779,064 for the year ended December 31, 2010 and $615,789 for the year
ended December 31, 2009. 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 at the inception of the Trust was $210,000. The Trustee paid ECA $390,072, $376,880 and $364,136 for overhead expenses for 2011, 2010 and 2009, 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.

F-11

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Table of Contents

EASTERN AMERICAN NATURAL GAS TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

6. Related Party Transactions: (Continued)

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.

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.

F-13

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Table of Contents

The
following table reconciles the change in proved reserves attributable to the Trust's share of the Net Profits Interests ("NPI") from January 1, 2009 to December 31,
2011:

Royalty
NPI

Term
NPI

Total
NPI(MMcf)

(MMcf)

(MMcf)Balance, January 1, 2009


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


10,700Production


(654
)

(877
)

(1,531
)Revisions of previous estimates


(152
)

131


(21
)Balance, December 31, 2010


7,577


1,571


9,148Production


(646
)

(841
)

(1,487
)Revisions of previous estimates


272


167


439Balance, December 31, 2011


7,203


897


8,100


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

Royalty
NPI

Term
NPI

Total
NPI(MMcf)

(MMcf)

(MMcf)December 31, 2009


8,383


2,317


10,700December 31, 2010


7,577


1,571


9,148December 31, 2011


7,203


897


8,100


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, 2011 (in thousands):

Royalty
NPI

Term
NPI

Total
NPIFuture cash inflows

$
48,726

$
5,339

$
54,065Future production taxes


(2,979
)

(267
)

(3,246
)Future production costs


(10,275
)

(655
)

(10,930
)Future net cash inflows


35,472


4,417


39,88910% discount factor


(20,309
)

(300
)

(20,609
)Standardized measure of discounted future net cash flows

$
15,163

$
4,117

$
19,280


F-14

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Table of Contents

The
following is the standardized measure of discounted future net cash flows as of December 31, 2010 (in thousands):

Royalty
NPI

Term
NPI

Total
NPIFuture cash inflows

$
55,156

$
9,919

$
65,075Future production taxes


(2,706
)

(418
)

(3,124
)Future production costs


(11,965
)

(1,107
)

(13,072
)Future net cash inflows


40,484


8,395


48,87910% discount factor


(23,327
)

(893
)

(24,220
)Standardized measure of discounted future net cash flows

$
17,157

$
7,502

$
24,659


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


F-15

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Table of Contents

Changes
in Standardized Measure of Discounted Future Net Cash Flows:

The
following schedule reconciles the changes during 2009, 2010 and 2011 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, 2009

$
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

$
30,458Net proceeds to the Trust


(5,703
)

(1,183
)

(6,886
)Revisions of previous estimates


(410
)

353


(57
)Accretion of discount


1,949


1,097


3,046Net change in price and production costs


(1,167
)

(217
)

(1,384
)Other


2,998


(3,516
)

(518
)Standardized measure, December 31, 2010

$
17,157

$
7,502

$
24,659Net proceeds to the Trust


(5,523
)

(688
)

(6,211
)Revisions of previous estimates


647


398


1,045Accretion of discount


1,716


750


2,466Net change in price and production costs


(2,185
)

(230
)

(2,415
)Other


3,351


(3,615
)

(264
)Standardized measure, December 31, 2011

$
15,163

$
4,117

$
19,280




The following is a summary of royalty income and distributable income per unit by quarter in 2011, 2010 and 2009 (all amounts in
thousands except Distributable income per unit):

2011

Mar 31

June 30

Sept 30

Dec 31

TotalRoyalty Income

$
1,746

$
1,912

$
1,921

$
1,744

$
7,323Distributable Income

$
1,052

$
1,587

$
1,432

$
1,192

$
5,263Distributable Income Per Unit

$
0.1784

$
0.2689

$
0.2427

$
0.2021

$
0.8921




2010

Mar 31

June 30

Sept 30

Dec 31

TotalRoyalty Income

$
2,153

$
2,067

$
2,060

$
1,892

$
8,172Distributable Income

$
1,308

$
1,530

$
1,548

$
1,344

$
5,730Distributable Income Per Unit

$
0.2217

$
0.2592

$
0.2625

$
0.2278

$
0.9712




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


F-16

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